Enbridge Inc./media... · ENBRIDGE INC. THIRD QUARTER REPORT 2017 | 1 Q3 HIGHLIGHTS (all financial...

Enbridge Inc.Third Quarter

Interim Report to ShareholdersFor the nine months ended September 30, 2017

ENBRIDGE INC. THIRD QUARTER REPORT 2017 | 1

Q3 HIGHLIGHTS (all financial figures are unaudited and in Canadian dollars unless otherwise noted) • Earnings were $765 million or $0.47 per common share for the third quarter and $2,322

million or $1.57 per common share for the nine-month period, both including the impact of a number of unusual, non-recurring or non-operating factors

• Adjusted earnings were $632 million or $0.39 per common share for the third quarter and

$1,969 million or $1.33 per common share for the nine-month period • Adjusted earnings before interest and income taxes (EBIT) were $1,738 million for the third

quarter and $4,966 million for the nine-month period • Available cash flow from operations (ACFFO) was $1,334 million or $0.82 per common

share for the third quarter and $3,873 million or $2.61 per common share for the nine-month period

• Management re-affirms 2017 ACFFO per share guidance range of $3.60-$3.90 per common share

• Line 3 Replacement Program progressing well with construction in Canada and in Wisconsin; Minnesota regulatory hearings under way

• Enbridge brought an additional $3 billion of growth projects into service since the end of the

second quarter of 2017

• Enbridge received an amended Presidential Permit for the expansion of the Alberta Clipper liquids pipeline

• Enbridge continues to execute on its funding plan, further strengthening its financial position with the issuance of nearly $3 billion of hybrid debt securities for which credit rating agencies assign 50% equity treatment

• Enbridge today announces that it intends to file with the Ontario Energy Board an application for amalgamation of Enbridge Gas Distribution Inc. and Union Gas Limited

CALGARY, ALBERTA – November 2, 2017 - Enbridge Inc. (Enbridge or the Company) (TSX:ENB) (NYSE:ENB) today reported third quarter 2017 adjusted EBIT of $1,738 million. Third quarter ACFFO was $1,334 million, or $0.82 per common share. This was the second full quarter of operations subsequent to the merger transaction with Spectra Energy Corp that closed on February 27, 2017 (the Merger Transaction). The largest driver of EBIT growth for the third quarter of 2017 relative to the third quarter of 2016 was the contribution from Enbridge’s new natural gas, liquids and utility assets acquired in the Merger Transaction. Also contributing to year-over-year EBIT growth was stronger crude oil throughput on the Mainline system, new projects coming into service in both the Liquids Pipelines and Gas


Pipelines and Processing segments, and stronger realized foreign exchange hedge rates. These positive contributors were partially offset by lower natural gas gathering and processing volumes and margins related to lower natural gas prices and drilling activity in certain areas, as well as slightly weaker results in the Green Power Transmission and Energy Services segments. Financial impacts from the hurricanes in the Gulf Coast region and Florida were not material to the quarterly results. ACFFO for the third quarter was $1,334 million, an increase of $482 million over the comparable prior period in 2016, driven largely by the same factors noted above. ACFFO of $0.82 per share was lower year-over-year primarily as a result of the issuance of additional shares as consideration under the Merger Transaction. “Overall, third quarter performance was in-line with our expectations,” said Al Monaco, Enbridge’s President and Chief Executive Officer. “Looking ahead to the fourth quarter, we anticipate a further acceleration of financial performance driven by increased liquids volumes, a full quarter of new projects in service, ongoing incremental synergy capture and momentum from the seasonal nature of our business which typically strengthens in the winter months. “Given these factors, along with the stable and reliable nature of the base business, we remain on track to deliver full year 2017 financial results within the previously disclosed guidance range of $3.60/share to $3.90/share.” Commenting on the continued execution of the business plan, Mr. Monaco noted: “We’ve had a very productive year so far. It’s now been only eight months since the Spectra transaction closed and we’re pleased with our progress on integrating operations of these two large companies. We’ve also made good strides in strengthening and streamlining the organization with the restructuring of Enbridge Energy Partners, L.P. and the buy-in of Midcoast Energy Partners, L.P. earlier this year. In addition, we’ve raised over $10 billion in the capital markets, of which $3 billion is equity or equity equivalent, and we’ve increased total non-core asset sales since the announcement of the Merger Transaction to $2.6 billion. “As we move forward, we’ll continue to evaluate ways to further strengthen and streamline both our business operations and sponsored vehicle structures, reduce costs and enhance our financial position,” he added. “We look forward to our upcoming investment community conferences on December 12th and 13th to provide a full strategic and financial update.” Line 3 Replacement Program The Line 3 Replacement is a critical energy infrastructure program that will support the economy and assure a reliable and cost-effective supply of energy. It will comprise the newest and most advanced pipeline technology and will enhance safety, reliability and throughput capacity on the Mainline system. All required regulatory permitting is in place in Canada and construction began this summer on certain segments of the pipeline and is progressing well. Regulatory permitting is also in place in North Dakota as well as in Wisconsin where construction is under way. The most significant remaining permitting process for the Line 3 Replacement Program is in Minnesota. The Final Environmental Impact Statement was issued in August and its adequacy determination is expected from the Minnesota Public Utilities Commission (MPUC) in


December. In the parallel Certificate of Need and Route Permit dockets, progress continues according to schedule with public hearings currently under way. The MPUC is expected to issue a decision on the Certificate of Need and Route Permit in the second quarter of 2018. Based on this regulatory process and timeline, Management continues to anticipate an in-service date for the project in the second half of 2019. Project Execution Enbridge continues to make good progress executing on its $31 billion secured growth capital program. These projects are supported by low-risk long-term take-or-pay contracts, cost-of-service frameworks or similar commercial arrangements and cover a wide range of business platforms, regulatory jurisdictions and project sizes. Since the second quarter of 2017, $3 billion of these projects were brought into service. This includes the JACOS Hangingstone crude oil pipeline lateral in Alberta, a suite of natural gas pipeline expansions and extensions on the Texas Eastern and Algonquin gas pipeline systems, the Chapman Ranch wind power generation project in Texas, as well as various utility growth initiatives in Ontario. This now brings the total year-to-date project completions to over $9 billion, generally all on time and on budget. Enbridge is also advancing the execution of projects scheduled for 2018 and 2019 in-service dates. The NEXUS gas pipeline has now received its notice to proceed from the Federal Energy Regulatory Commission (FERC) and began construction work in October. Total capital cost for the project has been updated to US$1.3 billion with an expected in-service date in the third quarter of 2018. In the renewable power business, the $0.8 billion Rampion offshore wind power generation project in the United Kingdom has now installed its final turbine with first power expected later this quarter and full operations in the second quarter of 2018. In addition, subsequent to quarter-end, Enbridge received an amended Presidential Permit for the Alberta Clipper (Line 67) expansion project. “We’re very pleased with the execution progress our Major Projects team is making on the secured project inventory”, said Mr. Monaco. “This progress highlights the fact that critical energy infrastructure projects are getting permitted and built in the current environment.” Funding Progress Enbridge continues to be pro-active with capital markets activities, making significant progress on the execution of its funding plan and improving its financial position. In particular, Enbridge has recently raised almost $3 billion of hybrid debt securities in the Canadian and United States markets on attractive terms. These instruments serve to further strengthen Enbridge’s balance sheet, as 50% of the principal is treated as equity capital by the credit rating agencies. During the quarter Enbridge also announced the sale of the St. Lawrence Gas utility in New York State for $0.1 billion, which is expected to close in 2018. This brings total non-core asset sales to $2.6 billion since last September, well above the Company’s target of $2.0 billion. “We’ve made good progress strengthening the balance sheet, in line with the prudent financing plan that we've shared with the credit ratings agencies”, added Mr. Monaco. “We continue to have broad access to capital, as demonstrated by the attractive financings we’ve completed in


both the Canadian and U.S. markets, and we’re committed to maintaining strong investment grade credit ratings.” Other Business Later today Enbridge plans to file an application with the Ontario Energy Board (OEB) to amalgamate Enbridge Gas Distribution Inc. and Union Gas Limited. Given the complimentary nature of these franchises, the amalgamation is expected to provide benefits to both the rate payers and the shareholders. This filing will initiate the regulatory review process which is expected to continue into 2018. Assuming an acceptable regulatory outcome, the amalgamation would be expected to take effect in 2019. Mr. Monaco concluded his third quarter remarks by acknowledging the Company’s response to the recent hurricanes. “I’d like to highlight how proud I am of the way our people responded to the difficult conditions caused by the hurricanes this past quarter. Not just through the great efforts by our teams to maintain the safe and reliable operations of our assets, but how they reached out and supported each other and our communities during this time of crisis. This demonstrates the quality of our people and how we’ve really come together as one company.”


THIRD QUARTER 2017 PERFORMANCE OVERVIEW For more information on Enbridge’s growth projects and operating results, please see Management’s Discussion and Analysis (MD&A) which is filed on SEDAR and EDGAR and also available on the Company’s website at www.enbridge.com/InvestorRelations.aspx. EARNINGS BEFORE INTEREST AND INCOME TAXES For the three and nine months ended September 30, 2017, EBIT increased by $2,088 million and $2,909 million, respectively, over the corresponding three and nine month periods in 2016. EBIT for the three and nine months ended September 30, 2017 were positively impacted by contributions from new assets of approximately $638 million and $1,478 million, respectively, following the completion of the Merger Transaction. The positive impact to EBIT for the three and nine months ended September 30, 2017, resulting from assets acquired in the Merger Transaction, was partially offset by weaker business performance in Liquids Pipelines and Energy Services as discussed in Adjusted Earnings Before Interest and Income Taxes below. The comparability of the Company’s earnings for the three and nine months ended September 30, 2017 was also impacted by a number of unusual, non-recurring or non-operating factors that are enumerated in the Non-GAAP Reconciliation tables, the most significant of which include:

• For the three and nine months ended September 30, 2016, the Company's EBIT reflected the recognition of an impairment of $1,000 million ($81 million after-tax attributable to Enbridge) related to Enbridge Energy Partners, L.P.'s (EEP) Sandpiper Project. There was no similar impairment in 2017.

• For the three months ended September 30, 2017, the Company’s EBIT reflected $362 million of unrealized derivative fair value gains, compared with losses of $14 million in the corresponding 2016 period. For the nine months ended September 30, 2017, the Company’s EBIT reflected $1,239 million of unrealized derivative fair value gains, compared with gains of $820 million in the corresponding 2016 period. The Company has a comprehensive long-term economic hedging program to mitigate interest rate, foreign exchange and commodity price risks which creates volatility in short-term earnings. Over the long-term, Enbridge believes its hedging program supports the reliable cash flows and dividend growth upon which the Company’s investor value proposition is based.

• For the nine months ended September 30, 2016, the Company's EBIT reflected the recognition of an impairment of $176 million ($103 million after-tax attributable to Enbridge) in the second quarter of 2016 related to Enbridge’s 75% joint venture interest in Eddystone Rail Company, LLC, a rail-to-barge transloading facility located in Greater Philadelphia, Pennsylvania. There was no similar impairment in 2017.

• For the nine months ended September 30, 2017, the Company's EBIT reflected charges of $180 million ($131 million after-tax) with respect to costs incurred in conjunction with the Merger Transaction, as well as $223 million ($157 million after-tax) of employee severance costs in relation to the Company’s enterprise-wide reduction of its workforce in March 2017 and restructuring costs in connection with the completion of the Merger Transaction.


EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS In addition to the factors discussed in Earnings Before Interest and Income Taxes above, interest expense for the three and nine months ended September 30, 2017 was higher, compared with the corresponding 2016 periods, primarily as a result of debt assumed in the Merger Transaction. Income tax expense increased for the three and nine months ended September 30, 2017, compared with the corresponding 2016 periods, largely due to the increase in earnings. Earnings attributable to noncontrolling interests and redeemable noncontrolling interests increased in the third quarter and the first nine months of 2017, compared with the corresponding 2016 periods. The increase was driven by additional noncontrolling interests associated with the assets acquired in the Merger Transaction and higher earnings attributable to noncontrolling interests in EEP during 2017. Higher earnings per common share for the three months ended September 30, 2017, compared with the corresponding 2016 period, is due to higher earnings, as discussed above, partially offset by the impact of the issuance of approximately 691 million common shares in February 2017 as part of the consideration for the Merger Transaction, the issuance of approximately 75 million common shares in 2016 through the public offering of 56 million common shares in the first quarter of 2016, and ongoing quarterly issuances under the Company’s Dividend Reinvestment Program. ADJUSTED EARNINGS BEFORE INTEREST AND INCOME TAXES For the three and nine months ended September 30, 2017, adjusted EBIT increased by $737 million and $1,502 million over the corresponding three and nine month periods in 2016. The largest driver of adjusted EBIT growth over the prior year periods was the contributions of new assets acquired in the Merger Transaction. The positive contributions from the acquired assets were partially offset by warmer weather in the franchise areas served by the Company’s gas distribution utilities and lower results in the Liquids Pipelines, Green Power and Transmission, and Energy Services segments. Growth in adjusted EBIT was most pronounced in the Gas Pipelines and Processing segment, where a majority of the new assets acquired through the Merger Transaction are reported. Growth for this segment also reflected contributions from the Tupper Main and Tupper West gas plants acquired in April 2016. Excluding contributions from Express-Platte following the Merger Transaction, Liquids Pipelines adjusted EBIT decreased in the three and nine months ended September 30, 2017, compared with the corresponding 2016 periods. The third quarter of 2017 benefited from higher throughput partly attributable to capacity optimization initiatives completed in the third quarter, which significantly reduced heavy crude oil apportionment allowing incremental heavy crude oil barrels to be shipped. These benefits to adjusted EBIT were offset by the absence of adjusted EBIT from certain assets that were divested since the third quarter of 2016 and a weaker United States to Canadian dollar exchange rate than in the prior quarter period. Liquids Pipelines reported performance was further impacted by a change in practice whereby the Company no longer includes cash received under certain take-or-pay contracts with make-up rights in its determination of adjusted EBIT.


The nine months ended September 30, 2017 were impacted by several transitory items noted in the second quarter of 2017 including a significant unexpected outage and accelerated maintenance at a customer’s upstream facility, additional related and unrelated production disruptions, and a hydrostatic testing program on Line 5. The combined impact on the mainline system of these factors was approximately $50 million. Up until the month of June, the mainline system had been delivering near record volumes and operating under significant apportionment in heavy crude oil service. Apportionment on the mainline system also impacted the adjusted EBIT contribution of certain downstream pipelines during the first and second quarters of 2017. Higher throughput, enabled by the capacity optimization initiatives noted above, is expected for the remainder of the year. Within the Gas Distribution segment, Enbridge Gas Distribution Inc. (EGD) generated lower adjusted EBIT for the nine months ended September 30, 2017, compared with the corresponding 2016 period, primarily due to lower distribution revenues attributable to warmer than normal weather in the first quarter of 2017. Effective January 1, 2017, EGD ceased to exclude the effect of warmer/colder weather from its adjusted EBIT. For the nine months ended September 30, 2017, warmer than normal weather impacted EGD’s adjusted EBIT by approximately $31 million. The period-over-period decrease in EGD’s adjusted EBIT was more than offset by contributions from Union Gas since the completion of the Merger Transaction. Energy Services adjusted EBIT for the three and nine months ended September 30, 2017 reflected compressed basis differentials in certain markets and fewer opportunities to achieve profitable margins on facilities which hold capacity obligations. Adjusted EBIT from Energy Services is dependent on market conditions and results achieved in one period may not be indicative of results to be achieved in future periods. The decrease in adjusted loss before interest and income taxes reported within Eliminations and Other reflects a portion of the synergies achieved thus far on integration of corporate functions and the impact of more favourable foreign exchange hedge settlements. ADJUSTED EARNINGS In addition to the factors discussed in Adjusted Earnings Before Interest and Income Taxes above, the comparability of adjusted earnings is consistent with the discussion in Earnings Attributable to Common Shareholders above.


AVAILABLE CASH FLOW FROM OPERATIONS ACFFO for the three months ended September 30, 2017 was $1,334 million, or $0.82 per common share, compared with $852 million, or $0.92 per common share, for the three months ended September 30, 2016. ACFFO was $3,873 million, or $2.61 per common share, for the nine months ended September 30, 2017, compared with $2,834 million, or $3.13 per common share, for the nine months ended September 30, 2016. The year-over-year growth in ACFFO was driven by the same factors as discussed in Adjusted Earnings Before Interest and Income Taxes above, as well as other items discussed below. However, ACFFO per common share has decreased quarter-over-quarter due to the increase in the number of common shares outstanding which resulted from the completion of the Merger Transaction, and other issuances in 2016, as noted above in Earnings Attributable to Common Shareholders. The above positive effects on ACFFO were partially offset by higher maintenance capital expenditures for the three and nine months ended September 30, 2017, which reflected the spending on assets acquired in the Merger Transaction. The increase was partially offset by a decrease in maintenance capital expenditures in the Gas Distribution segment where expenditures in 2016 were elevated as a result of higher spending on EGD’s Work and Asset Management System program; and a decrease in the third quarter, excluding the effect of the Merger Transaction, in the Liquids Pipelines segment due to a one-time maintenance project completed in 2016 which is absent in 2017. Also partially offsetting the increase in ACFFO was higher interest expense and higher preference share dividends for the three and nine months ended September 30, 2017, compared with the corresponding periods, as discussed in Earnings Attributable to Common Shareholders above. The increase in ACFFO was also impacted by the increased distributions to noncontrolling interests related to assets acquired in the Merger Transaction, which was partially offset by the decrease in distributions to noncontrolling interests in EEP resulting from the reduction in its quarterly distribution as well as the purchase of Midcoast Energy Partners, L.P.’s outstanding publicly-held common units. Refer to United States Sponsored Vehicle Strategy in the Company’s MD&A. Also offsetting the positive effects on ACFFO were higher distributions to redeemable noncontrolling interests due to increased public ownership in the Fund Group (comprising the Enbridge Income Fund, Enbridge Commercial Trust, Enbridge Income Partners LP (EIPLP) and the subsidiaries and investees of EIPLP) resulting from Enbridge Income Fund Holdings Inc.’s secondary offering in the second quarter of 2017. Other non-cash adjustments include various non-cash items presented in the Company’s Consolidated Statements of Cash Flows, as well as adjustments for unearned revenues received in each period.


FORWARD-LOOKING INFORMATION Forward-looking information, or forward-looking statements, have been included in this news release to provide information about the Company and its subsidiaries and affiliates, including management’s assessment of Enbridge and its subsidiaries’ future plans and operations. This information may not be appropriate for other purposes. Forward-looking statements are typically identified by words such as ‘‘anticipate’’, ‘‘expect’’, ‘‘project’’, ‘‘estimate’’, ‘‘forecast’’, ‘‘plan’’, ‘‘intend’’, ‘‘target’’, ‘‘believe’’, “likely” and similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information or statements included or incorporated by reference in this document include, but are not limited to, statements with respect to the following: expected EBIT or expected adjusted EBIT; expected earnings/(loss) or adjusted earnings/(loss); expected earnings/(loss) or adjusted earnings/(loss) per share; expected ACFFO or ACFFO per share; expected future cash flows; expected performance of the Liquids Pipelines business; financial strength and flexibility; expectations on sources of liquidity and sufficiency of financial resources; expected costs related to announced projects and projects under construction; expected in-service dates for announced projects and projects under construction; expected capital expenditures; expected impact on cash flows of the Company’s commercially secured growth program; expected future growth and expansion opportunities; expectations about the Company’s joint venture partners’ ability to complete and finance projects under construction; expected closing of acquisitions and dispositions; estimated future dividends; expected expansion of the T-South System; expected capacity of the Hohe See Expansion Offshore Wind Project; expected outcome of the Minnesota Public Utilities Commission review of the Line 3 Replacement Project; expected future actions of regulators; expected costs related to leak remediation and potential insurance recoveries; expectations regarding commodity prices; supply forecasts; expectations regarding the impact of the Merger Transaction including the combined Company’s scale, financial flexibility, growth program, future business prospects and performance; dividend payout policy; dividend growth and dividend payout expectation; and expectations on impact of hedging program. Although Enbridge believes these forward-looking statements are reasonable based on the information available on the date such statements are made and processes used to prepare the information, such statements are not guarantees of future performance and readers are cautioned against placing undue reliance on forward-looking statements. By their nature, these statements involve a variety of assumptions, known and unknown risks and uncertainties and other factors, which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Material assumptions include assumptions about the following: the expected supply of and demand for crude oil, natural gas, natural gas liquids (NGL) and renewable energy; prices of crude oil, natural gas, NGL and renewable energy; exchange rates; inflation; interest rates; availability and price of labour and construction materials; operational reliability; customer and regulatory approvals; maintenance of support and regulatory approvals for the Company’s projects; anticipated in-service dates; weather; the realization of anticipated benefits and synergies of the Merger Transaction; governmental legislation; acquisitions and the timing thereof; the success of integration plans; impact of capital project execution on the Company’s future cash flows; credit ratings; capital project funding; expected EBIT or expected adjusted EBIT; expected earnings/(loss) or adjusted earnings/(loss); expected earnings/(loss) or adjusted earnings/(loss) per share; expected future cash flows and expected future ACFFO and ACFFO per share; and estimated future dividends. Assumptions regarding the expected supply of and demand for crude oil, natural gas, NGL and renewable energy, and the prices of these commodities, are material to and underlie all forward-looking statements, as they may impact current and future levels of demand for the Company’s services. Similarly, exchange rates, inflation and interest rates impact the economies and business environments in which the Company operates and may impact levels of demand for the Company’s services and cost of inputs, and are therefore inherent in all forward-looking statements. Due to the interdependencies and correlation of these macroeconomic factors, the impact of any one assumption on a forward-looking statement cannot be determined with certainty, particularly with respect to the impact of the Merger Transaction on the Company, expected EBIT, adjusted EBIT, earnings/(loss), adjusted earnings/(loss) and associated per share amounts, or estimated future dividends. The most relevant assumptions associated with forward-looking statements on announced projects and projects under construction, including estimated completion dates and expected capital expenditures, include the


following: the availability and price of labour and construction materials; the effects of inflation and foreign exchange rates on labour and material costs; the effects of interest rates on borrowing costs; the impact of weather and customer, government and regulatory approvals on construction and in-service schedules and cost recovery regimes. Enbridge’s forward-looking statements are subject to risks and uncertainties pertaining to the impact of the Merger Transaction, operating performance, regulatory parameters, dividend policy, project approval and support, renewals of rights of way, weather, economic and competitive conditions, public opinion, changes in tax laws and tax rates, changes in trade agreements, exchange rates, interest rates, commodity prices, political decisions and supply of and demand for commodities, including but not limited to those risks and uncertainties discussed in this news release and in the Company’s other filings with Canadian and United States securities regulators. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these are interdependent and Enbridge’s future course of action depends on management’s assessment of all information available at the relevant time. Except to the extent required by applicable law, Enbridge assumes no obligation to publicly update or revise any forward-looking statements made in this news release or otherwise, whether as a result of new information, future events or otherwise. All subsequent forward-looking statements, whether written or oral, attributable to Enbridge or persons acting on the Company’s behalf, are expressly qualified in their entirety by these cautionary statements.


DIVIDEND DECLARATION On November 1, 2017, the Enbridge Board of Directors declared the following quarterly dividends. All dividends are payable on December 1, 2017, to shareholders of record on November 15, 2017.

Common Shares 0.61000 Preference Shares, Series A 0.34375 Preference Shares, Series B1 0.21340 Preference Shares, Series C2 0.19571 Preference Shares, Series D 0.25000 Preference Shares, Series F 0.25000 Preference Shares, Series H 0.25000 Preference Shares, Series J3 US$0.30540 Preference Shares, Series L4 US$0.30993 Preference Shares, Series N 0.25000 Preference Shares, Series P 0.25000 Preference Shares, Series R 0.25000 Preference Shares, Series 1 US$0.25000 Preference Shares, Series 3 0.25000 Preference Shares, Series 5 US$0.27500 Preference Shares, Series 7 0.27500 Preference Shares, Series 9 0.27500 Preference Shares, Series 11 0.27500 Preference Shares, Series 13 0.27500 Preference Shares, Series 15 0.27500 Preference Shares, Series 17 0.32188

1 The quarterly dividend amount of Series B was reset to $0.21340 from $0.25000 on June 1, 2017, due to reset on every fifth anniversary thereafter.

2 The quarterly dividend amount of Series C was set at $0.18600 on June 1, 2017 and $0.19571 on September 1, 2017, due to reset on a quarterly basis thereafter.

3 The quarterly dividend amount of Series J was reset to US$0.30540 from US$0.25000 on June 1, 2017, due to reset on every fifth anniversary thereafter.

4 The quarterly dividend amount of Series L was reset to US$0.30993 from US$0.25000 on September 1, 2017, due to reset on every fifth anniversary thereafter.


NON-GAAP MEASURES This news release contains references to adjusted EBIT, adjusted earnings, adjusted earnings per common share, ACFFO and ACFFO per common share. Adjusted EBIT represents EBIT adjusted for unusual, non-recurring or non-operating factors on both a consolidated and segmented basis. Adjusted earnings represent earnings attributable to common shareholders adjusted for unusual, non-recurring or non-operating factors included in adjusted EBIT, as well as adjustments for unusual, non-recurring or non-operating factors in respect of interest expense, income taxes, noncontrolling interests and redeemable noncontrolling interests on a consolidated basis. These factors, referred to as adjusting items, are reconciled and discussed in the financial results sections for the affected business segments in the Company’s MD&A. ACFFO is defined as cash flow provided by operating activities before changes in operating assets and liabilities (including changes in environmental liabilities) less distributions to noncontrolling interests and redeemable noncontrolling interests, preference share dividends and maintenance capital expenditures, and further adjusted for unusual, non-recurring or non-operating factors. Management believes the presentation of adjusted EBIT, adjusted earnings, adjusted earnings per common share, ACFFO and ACFFO per common share gives useful information to investors and shareholders as they provide increased transparency and insight into the performance of the Company. Management uses adjusted EBIT and adjusted earnings to set targets and to assess the performance of the Company. Management also uses ACFFO to assess the performance of the Company and to set its dividend payout target. Adjusted EBIT, adjusted EBIT for each segment, adjusted earnings, adjusted earnings per common share, ACFFO and ACFFO per common share are not measures that have standardized meaning prescribed by generally accepted accounting principles in the United States of America (U.S. GAAP) and are not U.S. GAAP measures. Therefore, these measures may not be comparable with similar measures presented by other issuers.


NON-GAAP RECONCILIATION – EBIT TO ADJUSTED EARNINGS

Three months ended

September 30, Nine months ended

September 30, 2017 2016 2017 2016 (millions of Canadian dollars)

Earnings/(loss) before interest and income taxes 1,995 (93) 5,723 2,814

Adjusting items1: Changes in unrealized derivative fair value (gain)/loss2 (362) 14 (1,239) (820) Sandpiper asset impairment3 — 1,000 — 1,000

Assets and investment impairment loss — 10 — 197

Unrealized intercompany foreign exchange (gain)/loss 6 (2) 20 53

Hydrostatic testing — (2) — (14) Make-up rights adjustments4 — 16 — 131

Northeastern Alberta wildfires pipelines and facilities restart costs —

18

—

39

Leak remediation costs, net of leak insurance recoveries 1

(13) 9

3

Warmer than normal weather5 — — — 8

Project development and transaction costs 3 27 206 30

Employee severance, transition and restructuring costs 76 22 284 30

Loss on sale of non-core assets and investment, net — 4 — 4

Other 19 — (37) (11) Adjusted earnings before interest and income taxes 1,738 1,001 4,966 3,464 Interest expense (653) (397) (1,704) (1,178) Income taxes (327) 253 (818) (174) (Earnings)/loss attributable to noncontrolling interests

and redeemable noncontrolling interests (168) 207 (633) 166

Preference share dividends (82) (73) (246) (217) Adjusting items in respect of:

Interest expense 39 12 37 36

Income taxes6 112 (330) 265 (210) Noncontrolling interests and redeemable noncontrolling

interests7 (27) (236) 102 (331)

Adjusted earnings 632 437 1,969 1,556

1 The above table summarizes adjusting items by nature. For a detailed listing of adjusting items by segment, refer to individual segment discussions in the Company’s MD&A.

2 Changes in unrealized derivative fair value gains and losses are presented net of amounts realized on the settlement of derivative contracts during the applicable period.

3 Inclusive of $8 million of related projects costs. 4 Effective January 1, 2017, the Company no longer makes such an adjustment to its EBIT. For further details refer to Financial

Results - Liquids Pipelines in the Company’s MD&A. 5 Effective January 1, 2017, the Company no longer makes such an adjustment to its EBIT. For further details refer to Financial

Results - Gas Distribution in the Company’s MD&A. 6 Income taxes were impacted by adjustments for unusual, non-recurring and non-operating factors as enumerated under adjusting

items for earnings before interest and incomes taxes. Refer to Earnings Attributable to Common Shareholders for additional information on the change for the three and nine months ended September 30, 2017, compared with the corresponding 2016 period.

7 Noncontrolling interest and redeemable noncontrolling interest were impacted by adjustments for unusual, non-recurring and non-operating factors as enumerated under adjusting items for earnings before interest and income taxes. Refer to Earnings Attributable to Common Shareholders for additional information on the change for the three and nine months ended September 30, 2017, compared with the corresponding 2016 period.


NON-GAAP RECONCILIATION – ADJUSTED EBIT TO ACFFO To facilitate understanding of the relationship between adjusted EBIT and ACFFO, the following table provides a reconciliation of these two key non-GAAP measures.

Three months ended



Adjusted earnings before interest and income taxes 1,738 1,001 4,966 3,464

Depreciation and amortization1 848 562 2,388 1,676

Maintenance capital expenditures2 (360) (171) (916) (466) 2,226 1,392 6,438 4,674

Interest expense3 (646) (385) (1,756) (1,142) Current income tax recovery/(expense)3 (22) 20 (105) (61) Distributions to noncontrolling interests3 (204) (176) (590) (538) Distributions to redeemable noncontrolling interests (63) (53) (180) (148) Preference share dividends (82) (73) (246) (217) Cash distributions in excess of equity earnings3 67 95 161 116

Other non-cash adjustments 58 32 151 150

Available cash flow from operations 1,334 852 3,873 2,834 1 Depreciation and amortization:

Liquids Pipelines 377 343 1,118 1,025 Gas Pipelines and Processing 241 73 627 222 Gas Distribution 157 87 426 251 Green Power and Transmission 48 47 149 142 Energy Services — — 1 1 Eliminations and Other 25 12 67 35

848 562 2,388 1,676 2 Maintenance capital expenditures:

Liquids Pipelines (42) (59) (147) (131) Gas Pipelines and Processing (151) (8) (344) (31) Gas Distribution (136) (86) (331) (251) Green Power and Transmission (30) (2) (91) (3) Eliminations and Other (1) (16) (3) (50)

(360) (171) (916) (466)

3 These balances are presented net of adjusting items.


NON-GAAP RECONCILIATION – ACFFO The following table provides a reconciliation of cash provided by operating activities (a GAAP measure) to ACFFO.

Three months ended


September 30, 2017 2016 2017 2016 (millions of Canadian dollars, except per share amounts)

Cash provided by operating activities 1,533 922 5,243 4,153

Adjusted for changes in operating assets and liabilities1 411 299 (49) 90

1,944 1,221 5,194 4,243 Distributions to noncontrolling interests2 (204) (176) (590) (538) Distributions to redeemable noncontrolling interests (63) (53) (180) (148) Preference share dividends (82) (73) (246) (217) Maintenance capital expenditures3 (360) (171) (916) (466) Significant adjusting items:

Weather normalization — — — 6

Make-up rights adjustments 21 29 63 142


Realized inventory revaluation allowance4 (39) (63) (39) (346) Employee severance, transition and restructuring

costs 72

22

278

30

Other items 43 89 108 98

Available cash flow from operations 1,334 852 3,873 2,834 Available cash flow from operations per common share 0.82 0.92 2.61 3.13

1 Changes in operating assets and liabilities include changes in environmental liabilities, net of recoveries. 2 This balance is presented net of adjusting items. 3 Maintenance capital expenditures are expenditures that are required for the ongoing support and maintenance of the existing

pipeline system or that are necessary to maintain the service capability of the existing assets (including the replacement of components that are worn, obsolete or completing their useful lives). For the purpose of ACFFO, maintenance capital excludes expenditures that extend asset useful lives, increase capacities from existing levels or reduce costs to enhance revenues or provide enhancements to the service capability of the existing assets.

4 Realized inventory revaluation allowance relates to losses on sale of previously written down inventory for which there is an approximate offsetting realized derivative gain in ACFFO.


MANAGEMENT’S DISCUSSION AND ANALYSIS FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2017 This Management’s Discussion and Analysis (MD&A) dated November 2, 2017 should be read in conjunction with the unaudited interim consolidated financial statements and notes thereto of Enbridge Inc. (Enbridge or the Company) as at and for the three and nine months ended September 30, 2017, prepared in accordance with generally accepted accounting principles in the United States of America (U.S. GAAP). It should also be read in conjunction with the Company’s audited consolidated financial statements and MD&A for the year ended December 31, 2016 filed on February 17, 2017. For information relating to assets and operations acquired through the combination with Spectra Energy Corp (Spectra Energy), additional information is also available in Spectra Energy’s audited consolidated financial statements and MD&A for the year ended December 31, 2016 filed on SEDAR on February 24, 2017. All financial measures presented in this MD&A are expressed in Canadian dollars, unless otherwise indicated. Additional information related to the Company, including its Annual Information Form, is available on SEDAR at www.sedar.com.

MERGER WITH SPECTRA ENERGY On February 27, 2017, Enbridge announced the closing of the previously announced combination of Enbridge and Spectra Energy through a stock-for-stock merger transaction (the Merger Transaction). Under the terms of the Merger Transaction, Spectra Energy shareholders received 0.984 shares of Enbridge for each share of Spectra Energy common stock they held. Upon closing of the Merger Transaction, Enbridge shareholders owned approximately 57% of the combined company and Spectra Energy shareholders owned approximately 43%. Spectra Energy, now wholly-owned by Enbridge, is one of North America’s leading natural gas delivery companies owning and operating a large, diversified and complementary portfolio of gas transmission, midstream gathering and processing and distribution assets. It also owns and operates a crude oil pipeline system that connects Canadian and United States producers to refineries in the United States Rocky Mountain and Midwest regions. The combination with Spectra Energy has created the largest energy infrastructure company in North America with an extensive portfolio of energy assets that are well positioned to serve key supply basins and end use markets and multiple business platforms through which to drive future growth. At the time of closing of the Merger Transaction, the Company’s capital program included $27 billion of commercially secured growth projects, which are expected to come into service through 2019, and an additional portfolio of projects in earlier stages of development expected to come into service by 2024. A more detailed description of each of the businesses and underlying assets acquired through the Merger Transaction is provided under Financial Results within this MD&A. The results of operations from assets acquired through the Merger Transaction are included in Enbridge’s financial statements and in this MD&A on a prospective basis from the closing date of the Merger Transaction. Post-combination, the Company’s activities continue to be carried out through five business segments: Liquids Pipelines; Gas Pipelines and Processing; Gas Distribution; Green Power and Transmission; and Energy Services. Effective February 27, 2017, as a result of the Merger Transaction, and in addition to Enbridge assets previously held:

• Liquids Pipelines also includes results from the operation of the Express-Platte System. • Gas Pipelines and Processing also includes Spectra Energy’s United States Storage and

Transmission Assets, Canadian Pipeline & Field Services, Canadian Midstream and Maritimes & Northeast U.S. and Canada businesses, as well as the results of the Company’s 50% interest in DCP Midstream, LLC (DCP Midstream).


• Gas Distribution also includes results from the operation of Union Gas Limited (Union Gas). A number of the assets acquired through the Merger Transaction and included in the business segments discussed above are owned through the Company’s investment in Spectra Energy Partners, LP (SEP). As a result of the combination, Enbridge now holds a 75% equity interest in SEP, a natural gas and crude oil infrastructure master limited partnership, which owns 100% of Texas Eastern Transmission, L.P. (Texas Eastern), 91% of Algonquin Gas Transmission, L.L.C. (Algonquin), 100% of East Tennessee Natural Gas, L.L.C. (East Tennessee), 100% of Express-Platte, 100% of Saltville Gas Storage Company L.L.C. (Saltville), 100% of Ozark Gas Gathering, L.L.C. and Ozark Gas Transmission, L.L.C., 100% of Big Sandy Pipeline, L.L.C., 100% of Market Hub Partners Holding, 100% of Bobcat Gas Storage, 78% of Maritimes & Northeast Pipeline, L.L.C. (M&N U.S.), 50% of Southeast Supply Header, L.L.C., 50% of Steckman Ridge, L.P., 50% of Gulfstream Natural Gas System, L.L.C. (Gulfstream) and 50% of Sabal Trail Transmission LLC (Sabal Trail).

UNITED STATES SPONSORED VEHICLE STRATEGY On April 28, 2017, Enbridge announced the completion of a strategic review of Enbridge Energy Partners, L.P. (EEP). The following actions, together with the measures announced in January 2017 and disclosed in the Company’s 2016 annual MD&A, were taken to enhance EEP’s value proposition to its unitholders and to Enbridge: Acquisition of Midcoast Assets and Privatization of Midcoast Energy Partners, L.P. On April 27, 2017, Enbridge completed its previously-announced merger through a wholly-owned subsidiary, through which it privatized Midcoast Energy Partners, L.P. (MEP) by acquiring all of the outstanding publicly-held common units of MEP for total consideration of approximately US$170 million. On June 28, 2017, Enbridge, through a wholly-owned subsidiary, acquired all of EEP’s interest in the Midcoast gas gathering and processing business for cash consideration of US$1.3 billion plus existing indebtedness of MEP of US$953 million. As a result of the above transactions, 100% of the Midcoast gas gathering and processing business is now owned by Enbridge. Finalization of Bakken Pipeline System Joint Funding Agreement On February 15, 2017, EEP acquired an effective 27.6% interest in the Dakota Access and Energy Transfer Crude Oil Pipelines (collectively, the Bakken Pipeline System). On April 27, 2017, Enbridge entered into a joint funding arrangement with EEP whereby Enbridge owns 75% and EEP owns 25% of the combined 27.6% effective interest in the Bakken Pipeline System. Under this arrangement, EEP has retained a five-year option to acquire an additional 20% interest. On finalization of this joint funding arrangement, EEP repaid the outstanding balance on its US$1.5 billion credit agreement with Enbridge, which it had drawn upon to fund the initial purchase. EEP Strategic Restructuring Actions On April 27, 2017, EEP redeemed all of its outstanding Series 1 Preferred Units held by Enbridge at face value of US$1.2 billion through the issuance of 64.3 million Class A common units to Enbridge. Further, Enbridge irrevocably waived all of its rights associated with its ownership of 66.1 million Class D units and 1,000 Incentive Distribution Units (IDUs) of EEP, in exchange for the issuance of 1,000 Class F units. The Class F units are entitled to (i) 13% of all distributions in excess of US$0.295 per EEP unit, but equal to or less than US$0.35 per EEP unit, and (ii) 23% of all distributions in excess of US$0.35 per EEP unit. The irrevocable waiver is effective with respect to distributions declared with a record date after April 27, 2017. In connection with these strategic restructuring actions, EEP reduced its quarterly distribution from US$0.583 per unit to US$0.35 per unit.


The irrevocable waiver of the Class D units and IDUs, the redemption of the Series 1 Preferred Units and the reduction in the quarterly distributions will result in a lower contribution of earnings from EEP. This lower contribution will be partially offset by an increased contribution of earnings as a result of Enbridge’s increased ownership in the Class A common units post restructuring.

ASSET MONETIZATION On April 18, 2017, the Company and Enbridge Income Fund Holdings Inc. (ENF) completed the secondary offering of 17,347,750 ENF common shares to the public at a price of $33.15 per share, for gross proceeds to Enbridge of approximately $0.6 billion (the Secondary Offering). To effect the Secondary Offering, Enbridge exchanged 21,657,617 Enbridge Income Fund (Fund) units it owned for an equivalent amount of ENF common shares. In order to maintain its 19.9% ownership interest in ENF, Enbridge retained 4,309,867 of the common shares it received in the exchange, and sold the balance under the Secondary Offering. Enbridge used the proceeds from the Secondary Offering to pay down short-term debt, pending reinvestment by the Company in its growing portfolio of secured projects. Upon closing of the Secondary Offering, the Company’s total economic interest in ENF decreased from 86.9% to 84.6%. In conjunction with the announcement of the Merger Transaction in September 2016, the Company announced its intention to divest of $2 billion of assets over the ensuing 12 months in order to further strengthen its post-combination balance sheet and enhance the financial flexibility of the combined entity. With the completion of the Secondary Offering noted above, the Ozark pipeline system sale, the Olympic refined products pipeline sale and other divestitures completed in 2016 and previously disclosed, the Company has exceeded the $2 billion monetization target.

ALBERTA CLIPPER (LINE 67) PRESIDENTIAL PERMIT On October 16, 2017, the Company received a Presidential Permit for Line 67, following a nearly five-year process of review. Line 67 currently operates under an existing Presidential Permit that was issued by the State Department in 2009 and the 2017 Presidential Permit authorizes the Company to fully utilize its capacity across the border. Line 67 is a key component of the Company's mainline system, which United States refineries rely on to provide vital products to consumers across the midwest United States. For additional information on Line 67, refer to Growth Projects - Commercially Secured Projects - Liquids Pipelines - Lakehead System Mainline Expansion.


FORWARD-LOOKING INFORMATION Forward-looking information, or forward-looking statements, have been included in this MD&A to provide information about the Company and its subsidiaries and affiliates, including management’s assessment of Enbridge and its subsidiaries’ future plans and operations. This information may not be appropriate for other purposes. Forward-looking statements are typically identified by words such as ‘‘anticipate”, “expect”, “project”, “estimate”, “forecast”, “plan”, “intend”, “target”, “believe”, “likely” and similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information or statements included or incorporated by reference in this document include, but are not limited to, statements with respect to the following: expected EBIT or expected adjusted EBIT; expected earnings/(loss) or adjusted earnings/(loss); expected earnings/(loss) or adjusted earnings/(loss) per share; expected future cash flows; expected performance of the Liquids Pipelines business; financial strength and flexibility; expectations on sources of liquidity and sufficiency of financial resources; expected costs related to announced projects and projects under construction; expected in-service dates for announced projects and projects under construction; expected capital expenditures; expected equity funding requirements for the Company’s commercially secured growth program; expected future growth and expansion opportunities; expectations about the Company’s joint venture partners’ ability to complete and finance projects under construction; expected closing of acquisitions and dispositions; estimated future dividends; recovery of the costs of the Canadian portion of the Line 3 Replacement Program (Canadian L3R Program); expected expansion of the T-South System and Spruce Ridge Program; expected capacity of the Hohe See Expansion Offshore Wind Project; expected costs in connection with Line 6A and Line 6B crude oil releases; expected effect of Aux Sable Consent Decree; expected future actions of regulators; expected costs related to leak remediation and potential insurance recoveries; expectations regarding commodity prices; supply forecasts; expectations regarding the impact of the Merger Transaction including the combined Company’s scale, financial flexibility, growth program, future business prospects and performance; impact of the Canadian L3R Program on existing integrity programs; the sponsored vehicle strategy; dividend payout policy; dividend growth and dividend payout expectation; and expectations on impact of hedging program. Although Enbridge believes these forward-looking statements are reasonable based on the information available on the date such statements are made and processes used to prepare the information, such statements are not guarantees of future performance and readers are cautioned against placing undue reliance on forward-looking statements. By their nature, these statements involve a variety of assumptions, known and unknown risks and uncertainties and other factors, which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Material assumptions include assumptions about the following: the expected supply of and demand for crude oil, natural gas, natural gas liquids (NGL) and renewable energy; prices of crude oil, natural gas, NGL and renewable energy; exchange rates; inflation; interest rates; availability and price of labour and construction materials; operational reliability; customer and regulatory approvals; maintenance of support and regulatory approvals for the Company’s projects; anticipated in-service dates; weather; the realization of anticipated benefits and synergies of the Merger Transaction; governmental legislation; acquisitions and the timing thereof; the success of integration plans; impact of the dividend policy on the Company’s future cash flows; credit ratings; capital project funding; expected EBIT or expected adjusted EBIT; expected earnings/(loss) or adjusted earnings/(loss); expected earnings/(loss) or adjusted earnings/(loss) per share; expected future cash flows and estimated future dividends. Assumptions regarding the expected supply of and demand for crude oil, natural gas, NGL and renewable energy, and the prices of these commodities, are material to and underlie all forward-looking statements, as they may impact current and future levels of demand for the Company’s services. Similarly, exchange rates, inflation and interest rates impact the economies and business environments in which the Company operates and may impact levels of demand for the Company’s services and cost of inputs, and are therefore inherent in all forward-looking statements. Due to the interdependencies and correlation of these macroeconomic factors, the impact of any one assumption on a forward-looking statement cannot be determined with certainty, particularly with respect to the impact of the Merger Transaction on the Company, expected EBIT, adjusted EBIT, earnings/(loss), adjusted earnings/(loss) and associated per share amounts, or estimated future dividends. The most relevant assumptions associated with forward-looking statements on announced projects and projects under construction, including estimated completion dates and expected capital expenditures, include the following: the availability and price of labour and construction materials; the effects of inflation and foreign exchange rates on labour and material costs; the effects of interest rates on borrowing costs; the impact of weather and customer, government and regulatory approvals on construction and in-service schedules and cost recovery regimes.


Enbridge’s forward-looking statements are subject to risks and uncertainties pertaining to the impact of the Merger Transaction, operating performance, regulatory parameters, dividend policy, project approval and support, renewals of rights of way, weather, economic and competitive conditions, public opinion, changes in tax laws and tax rates, changes in trade agreements, exchange rates, interest rates, commodity prices, political decisions and supply of and demand for commodities, including but not limited to those risks and uncertainties discussed in this MD&A and in the Company’s other filings with Canadian and United States securities regulators. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these are interdependent and Enbridge’s future course of action depends on management’s assessment of all information available at the relevant time. Except to the extent required by applicable law, Enbridge assumes no obligation to publicly update or revise any forward-looking statements made in this MD&A or otherwise, whether as a result of new information, future events or otherwise. All subsequent forward-looking statements, whether written or oral, attributable to Enbridge or persons acting on the Company’s behalf, are expressly qualified in their entirety by these cautionary statements.


CONSOLIDATED EARNINGS

Three months ended



Liquids Pipelines 1,326 (87 ) 3,722 2,168

Gas Pipelines and Processing 615 67 1,636 147

Gas Distribution 83 20 511 342

Green Power and Transmission 20 34 121 124

Energy Services (150) (25 ) (12) (38 ) Eliminations and Other 101 (102 ) (255) 71

Earnings/(loss) before interest and income taxes 1,995 (93 ) 5,723 2,814 Interest expense (653) (397 ) (1,704) (1,178 ) Income tax recovery/(expense) (327) 253 (818) (174 ) (Earnings)/loss attributable to noncontrolling interests


Preference share dividends (82) (73 ) (246) (217 ) Earnings/(loss) attributable to common shareholders 765 (103 ) 2,322 1,411

Earnings/(loss) per common share 0.47 (0.11 ) 1.57 1.56 Diluted earnings/(loss) per common share 0.47 (0.11 ) 1.56 1.55

EARNINGS BEFORE INTEREST AND INCOME TAXES For the three and nine months ended September 30, 2017, earnings before interest and income taxes (EBIT) increased by $2,088 million and $2,909 million, respectively, over the corresponding three and nine month periods in 2016. EBIT for the three and nine months ended September 30, 2017 were positively impacted by contributions from new assets of approximately $638 million and $1,478 million, respectively, following the completion of the Merger Transaction. The positive impact to EBIT for the three and nine months ended September 30, 2017, resulting from assets acquired in the Merger Transaction, was partially offset by weaker business performance in Liquids Pipelines and Energy Services as discussed in Adjusted EBIT below. The comparability of the Company’s earnings for the three and nine months ended September 30, 2017 was also impacted by a number of unusual, non-recurring or non-operating factors that are enumerated in the Non-GAAP Reconciliation tables, the most significant of which include:

• For the three and nine months ended September 30, 2016, the Company's EBIT reflected the recognition of an impairment of $1,000 million ($81 million after-tax attributable to Enbridge) related to EEP's Sandpiper Project. There was no similar impairment in 2017.

• For the three months ended September 30, 2017, the Company’s EBIT reflected $362 million of unrealized derivative fair value gains, compared with losses of $14 million in the corresponding 2016 period. For the nine months ended September 30, 2017, the Company’s EBIT reflected $1,239 million of unrealized derivative fair value gains, compared with gains of $820 million in the corresponding 2016 period. The Company has a comprehensive long-term economic hedging program to mitigate interest rate, foreign exchange and commodity price risks which creates volatility in short-term earnings. Over the long-term, Enbridge believes its hedging program supports the reliable cash flows and dividend growth upon which the Company’s investor value proposition is based.

• For the nine months ended September 30, 2016, the Company's EBIT reflected the recognition of an impairment of $176 million ($103 million after-tax attributable to Enbridge) in the second quarter of 2016 related to Enbridge’s 75% joint venture interest in Eddystone Rail Company, LLC (Eddystone Rail), a rail-to-barge transloading facility located in Greater Philadelphia, Pennsylvania. There was no similar impairment in 2017.


• For the nine months ended September 30, 2017, the Company's EBIT reflected charges of $180 million ($131 million after-tax) with respect to costs incurred in conjunction with the Merger Transaction, as well as $223 million ($157 million after-tax) of employee severance costs in relation to the Company’s enterprise-wide reduction of its workforce in March 2017 and restructuring costs in connection with the completion of the Merger Transaction.

EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS In addition to the factors discussed in Earnings Before Interest and Income Taxes above, interest expense for the three and nine months ended September 30, 2017 was higher, compared with the corresponding 2016 periods, primarily as a result of debt assumed in the Merger Transaction. Income tax expense increased for the three and nine months ended September 30, 2017, compared with the corresponding 2016 periods, largely due to the increase in earnings. Earnings attributable to noncontrolling interests and redeemable noncontrolling interests increased in the third quarter and the first nine months of 2017, compared with the corresponding 2016 periods. The increase was driven by additional noncontrolling interests associated with the assets acquired in the Merger Transaction and higher earnings attributable to noncontrolling interests in EEP during 2017. Higher earnings per common share for the three months ended September 30, 2017, compared with the corresponding 2016 period, is due to higher earnings, as discussed above, partially offset by the impact of the issuance of approximately 691 million common shares in February 2017 as part of the consideration for the Merger Transaction, the issuance of approximately 75 million common shares in 2016 through the public offering of 56 million common shares in the first quarter of 2016, and ongoing quarterly issuances under the Company’s Dividend Reinvestment Program.

NON-GAAP MEASURES This MD&A contains references to adjusted EBIT, adjusted earnings and adjusted earnings per common share. Adjusted EBIT represents EBIT adjusted for unusual, non-recurring or non-operating factors on both a consolidated and segmented basis. Adjusted earnings represent earnings attributable to common shareholders adjusted for unusual, non-recurring or non-operating factors included in adjusted EBIT, as well as adjustments for unusual, non-recurring or non-operating factors in respect of interest expense, income taxes, noncontrolling interests and redeemable noncontrolling interests on a consolidated basis. These factors, referred to as adjusting items, are reconciled and discussed in the financial results sections for the affected business segments. Management believes the presentation of adjusted EBIT, adjusted earnings and adjusted earnings per share gives useful information to investors and shareholders as they provide increased transparency and insight into the performance of the Company. Management uses adjusted EBIT and adjusted earnings to set targets and to assess the performance of the Company. Adjusted EBIT, adjusted EBIT for each segment, adjusted earnings and adjusted earnings per common share are not measures that have standardized meaning prescribed by U.S. GAAP and are not U.S. GAAP measures. Therefore, these measures may not be comparable with similar measures presented by other issuers. The tables below provide a reconciliation of the GAAP and non-GAAP measures.


NON-GAAP RECONCILIATION EBIT TO ADJUSTED EARNINGS

Three months ended



Earnings/(loss) before interest and income taxes 1,995 (93 ) 5,723 2,814

Adjusting items1: Changes in unrealized derivative fair value (gain)/loss2 (362) 14 (1,239) (820 ) Sandpiper asset impairment3 — 1,000 — 1,000

Assets and investment impairment loss — 10 — 197

Unrealized intercompany foreign exchange (gain)/loss 6 (2 ) 20 53

Hydrostatic testing — (2 ) — (14 ) Make-up rights adjustments4 — 16 — 131

Northeastern Alberta wildfires pipelines and facilities restart costs —

18

—

39

Leak remediation costs, net of leak insurance recoveries 1

(13 ) 9

3

Warmer than normal weather5 — — — 8


Employee severance, transition and restructuring costs 76 22 284 30

Loss on sale of non-core assets and investments, net — 4 — 4

Other 19 — (37) (11 ) Adjusted earnings before interest and income taxes 1,738 1,001 4,966 3,464 Interest expense (653) (397 ) (1,704) (1,178 ) Income taxes (327) 253 (818) (174 ) (Earnings)/loss attributable to noncontrolling interests


Preference share dividends (82) (73 ) (246) (217 ) Adjusting items in respect of:

Interest expense 39 12 37 36

Income taxes6 112 (330 ) 265 (210 ) Noncontrolling interests and redeemable noncontrolling

interests7 (27) (236 ) 102

(331 )

Adjusted earnings 632 437 1,969 1,556

1 The above table summarizes adjusting items by nature. For a detailed listing of adjusting items by segment, refer to individual segment discussions.

2 Changes in unrealized derivative fair value gains and losses are presented net of amounts realized on the settlement of derivative contracts during the applicable period.

3 Inclusive of $8 million of related projects costs. 4 Effective January 1, 2017, the Company no longer makes such an adjustment to its EBIT. For further details refer to Financial

Results - Liquids Pipelines. 5 Effective January 1, 2017, the Company no longer makes such an adjustment to its EBIT. For further details refer to Financial

Results - Gas Distribution. 6 Income taxes were impacted by adjustments for unusual, non-recurring and non-operating factors as enumerated under adjusting

items for earnings before interest and incomes taxes. Refer to Earnings Attributable to Common Shareholders for additional information on the change for the three and nine months ended September 30, 2017, compared with the corresponding 2016 period.

7 Noncontrolling interest and redeemable noncontrolling interest were impacted by adjustments for unusual, non-recurring and non-operating factors as enumerated under adjusting items for earnings before interest and income taxes. Refer to Earnings Attributable to Common Shareholders for additional information on the change for the three and nine months ended September 30, 2017, compared with the corresponding 2016 period.


ADJUSTED EBIT TO ADJUSTED EARNINGS

Three months ended



Liquids Pipelines 976 941 2,884 2,947

Gas Pipelines and Processing 700 94 1,703 271

Gas Distribution 81 31 503 344


Energy Services (24) (15 ) (32) 33

Eliminations and Other (15) (84 ) (213) (253 ) Adjusted earnings before interest and income taxes 1,738 1,001 4,966 3,464 Interest expense1 (614) (385 ) (1,667) (1,142 ) Income taxes1 (215) (77 ) (553) (384 ) Noncontrolling interests and redeemable noncontrolling

interests1 (195) (29 ) (531) (165 )

Preference share dividends (82) (73 ) (246) (217 ) Adjusted earnings 632 437 1,969 1,556

Adjusted earnings per common share 0.39 0.47 1.33 1.72 1 These balances are presented net of adjusting items.

Adjusted EBIT For the three and nine months ended September 30, 2017, adjusted EBIT increased by $737 million and $1,502 million over the corresponding three and nine month periods in 2016. The largest driver of adjusted EBIT growth over the prior year periods was the contributions of new assets acquired in the Merger Transaction. The positive contributions from the acquired assets were partially offset by warmer weather in the franchise areas served by the Company’s gas distribution utilities and lower results in the Liquids Pipelines, Green Power and Transmission, and Energy Services segments. Growth in adjusted EBIT was most pronounced in the Gas Pipelines and Processing segment, where a majority of the new assets acquired through the Merger Transaction are reported. Growth for this segment also reflected contributions from the Tupper Main and Tupper West gas plants (the Tupper Plants) acquired in April 2016. Excluding contributions from Express-Platte following the Merger Transaction, Liquids Pipelines adjusted EBIT decreased in the three and nine months ended September 30, 2017, compared with the corresponding 2016 periods. The third quarter of 2017 benefited from higher throughput partly attributable to capacity optimization initiatives completed in the third quarter, which significantly reduced heavy crude oil apportionment allowing incremental heavy crude oil barrels to be shipped. These benefits to adjusted EBIT were offset by the absence of adjusted EBIT from certain assets that were divested since the third quarter of 2016 and a weaker United States to Canadian dollar exchange rate (Average Exchange Rate) than in the prior quarter period. Liquids Pipelines reported performance was further impacted by a change in practice whereby the Company no longer includes cash received under certain take-or-pay contracts with make-up rights in its determination of adjusted EBIT. The nine months ended September 30, 2017 were impacted by several transitory items noted in the second quarter of 2017 including a significant unexpected outage and accelerated maintenance at a customer’s upstream facility, additional related and unrelated production disruptions, and a hydrostatic testing program on Line 5. The combined impact on the mainline system of these factors was approximately $50 million. Up until the month of June, the mainline system had been delivering near record volumes and operating under significant apportionment in heavy crude oil service. Apportionment on the mainline system also impacted the adjusted EBIT contribution of certain downstream pipelines


during the first and second quarters of 2017. Higher throughput, enabled by the capacity optimization initiatives noted above, is expected for the remainder of the year. Within the Gas Distribution segment, Enbridge Gas Distribution Inc. (EGD) generated lower adjusted EBIT for the nine months ended September 30, 2017, compared with the corresponding 2016 period, primarily due to lower distribution revenues attributable to warmer than normal weather in the first quarter of 2017. Effective January 1, 2017, EGD ceased to exclude the effect of warmer/colder weather from its adjusted EBIT. For the nine months ended September 30, 2017, warmer than normal weather impacted EGD’s adjusted EBIT by approximately $31 million. The period-over-period decrease in EGD’s adjusted EBIT was more than offset by contributions from Union Gas since the completion of the Merger Transaction. Energy Services adjusted EBIT for the three and nine months ended September 30, 2017 reflected compressed basis differentials in certain markets and fewer opportunities to achieve profitable margins on facilities which hold capacity obligations. Adjusted EBIT from Energy Services is dependent on market conditions and results achieved in one period may not be indicative of results to be achieved in future periods. The decrease in adjusted loss before interest and income taxes reported within Eliminations and Other reflects a portion of the synergies achieved thus far on integration of corporate functions and the impact of more favourable foreign exchange hedge settlements. Adjusted Earnings In addition to the factors discussed in Adjusted EBIT above, the comparability of adjusted earnings is consistent with the discussion in Earnings Attributable to Common Shareholders above.

FINANCIAL RESULTS For assets owned by Enbridge as at December 31, 2016, a description of the asset and associated risks can be found under the relevant segment discussion in the Company’s MD&A for the year ended December 31, 2016. For assets acquired through the Merger Transaction, the description of the asset and any additional risks specifically associated with these assets have been included with the discussion of the operating results of individual assets that follows. The performance summaries below include the financial results of the assets acquired in the Merger Transaction from the closing date.


LIQUIDS PIPELINES Earnings Before Interest and Income Taxes

Three months ended



Canadian Mainline 265 206 736 692

Lakehead System 287 331 976 1,043

Regional Oil Sands System 106 105 290 286

Mid-Continent and Gulf Coast 133 163 379 504

Southern Lights Pipeline 47 44 132 124

Express-Platte System1 58 — 141 —

Bakken System 52 48 134 156

Feeder Pipelines and Other 28 44 96 142

Adjusted earnings before interest and income taxes 976 941 2,884 2,947

Canadian Mainline - changes in unrealized derivative fair value gain/(loss) 326

(7 ) 747

549

Canadian Mainline - leak remediation costs (3) — (15) —

Lakehead system - changes in unrealized derivative fair value gain/(loss) (1) 1

1

(4 )

Lakehead System - hydrostatic testing — 2 — 14

Lakehead System - leak remediation costs — — — (21 ) Lakehead System - leak insurance recoveries — 13 — 13

Lakehead System - transition costs (18) — (18) —

Regional Oil Sands System - northeastern Alberta wildfire pipelines and facilities restart costs —

(18 ) —

(39 )

Regional Oil Sands System - make-up rights2 — 3 — (31 ) Regional Oil Sands System - leak insurance recoveries 3 — 6 5

Mid-Continent and Gulf Coast - changes in unrealized derivative fair value loss —

—

—

(1 )

Mid-Continent and Gulf Coast - make-up rights2 — (19 ) — (97 ) Mid-Continent and Gulf Coast - transition costs (1) — (1) —

Southern Lights Pipeline - changes in unrealized derivative fair value gain/(loss) 17

(1 ) 33

25

Express-Platte System - changes in unrealized derivative fair value loss (1) —

(1) —

Bakken System - Sandpiper asset impairment — (1,000 ) — (1,000 ) Bakken System - changes in unrealized derivative fair

value gain/(loss) 1

— 1

(3 )

Bakken System - make-up rights2 — 1 — 1

Bakken System - gain on sale of pipe and project wind-down costs 4

—

66

—

Bakken System - transition costs (2) — (2) —

Feeder Pipelines and Other - gain on sale of asset 27 — 27 —

Feeder Pipelines and Other - investment impairment — (2 ) — (178 ) Feeder Pipelines and Other - derecognition of regulatory

balances —

— —

(6 )

Feeder Pipelines and Other - make-up rights2 — (1 ) — (3 ) Feeder Pipelines and Other - project development and

transaction costs (2) — (6) (3 )

Earnings/(loss) before interest and income taxes 1,326 (87 ) 3,722 2,168

1 Includes adjusted EBIT from Express-Platte System since the completion of the Merger Transaction. For additional information, refer to Merger with Spectra Energy.

2 Effective January 1, 2017, the Company no longer makes such an adjustment to its EBIT.


Additional details on items impacting Liquids Pipelines EBIT include:

• Canadian Mainline EBIT for each period reflects changes in unrealized fair value gains and losses on derivative financial instruments used to manage foreign exchange and commodity price risk inherent within the Competitive Toll Settlement (CTS).

• Bakken System loss before interest and income taxes for 2016 reflected impairment charges, including related project costs, on EEP's Sandpiper Project resulting from the withdrawal of the regulatory application in September 2016 that were pending with the Minnesota Public Utilities Commission (MNPUC).

• Bakken System EBIT for 2017 includes the gain on sale of pipe offset by project wind-down costs related to EEP’s Sandpiper Project.

• Feeder Pipelines and Other loss before interest and income taxes for 2016 included impairment charges related to Enbridge’s 75% joint venture interest in Eddystone Rail attributable to market conditions that reduced volumes at the rail facility.

Canadian Mainline Canadian Mainline adjusted EBIT increased in the third quarter of 2017, compared with the corresponding 2016 period, primarily due to a higher average Canadian Mainline International Joint Tariff (IJT) Residual Benchmark Toll, higher toll surcharges and higher average throughput. The Canadian Mainline also benefitted from a higher foreign exchange hedge rate used to record Canadian Mainline revenues. For the third quarter of 2017, the effective hedged rate for the translation of Canadian Mainline United States dollar transactional revenues was $1.07, compared with $1.05 for the corresponding 2016 period. The higher surcharge revenue in the third quarter of 2017 resulted from the recovery of hydrotest costs and the recovery of costs on certain expansion projects. Higher average throughput in the third quarter of 2017, compared with the corresponding 2016 period, was driven by continued strong oil sands production and downstream demand. The additional throughput was realized through the capacity optimization initiatives enabled in the third quarter of 2017. This resulted in significantly lower heavy crude oil apportionment and incremental heavy crude oil barrels shipped. Canadian Mainline adjusted EBIT increased for the nine months ended September 30, 2017, compared with the corresponding 2016 period, primarily due to strong third quarter results discussed above. This increase was partially offset by lower first half results due to the absence of hydrostatic test surcharge revenue and a lower foreign exchange hedge rate used to record Canadian Mainline revenues. For the first half of 2017, the effective hedged rate for the translation of Canadian Mainline United States dollar transactional revenues was $1.04 compared with $1.07 for the corresponding 2016 period. Relative to 2016, throughput volumes were slightly higher in the first quarter of 2017 and significantly higher in the second quarter of 2017 due to the non-recurrence of the negative impact of the northeastern Alberta wildfires experienced in 2016. The wildfires resulted in a curtailment of production from oil sands facilities and certain of the Company's upstream pipelines and terminal facilities were shut down, decreasing second quarter 2016 adjusted EBIT by approximately $30 million. Second quarter 2017 throughput volumes were negatively affected by the unexpected outage and accelerated maintenance program at a customer's upstream facility, and additional related and unrelated production disruptions which adversely impacted the second quarter of 2017.


Supplemental information related to the Canadian Mainline for the three and nine months ended September 30, 2017 and 2016, is provided below:

September 30, 2017 2016 (United States dollars per barrel)

IJT Benchmark Toll1 $4.07 $4.05 Lakehead System Local Toll2 $2.43 $2.58 Canadian Mainline IJT Residual Benchmark Toll3 $1.64 $1.47

1 The IJT Benchmark Toll is per barrel of heavy crude oil transported from Hardisty, Alberta to Chicago, Illinois. A separate distance adjusted toll applies to shipments originating at receipt points other than Hardisty and lighter hydrocarbon liquids pay a lower toll than heavy crude oil. Effective July 1, 2016, this toll decreased to US$4.05. Effective July 1, 2017, this toll increased to US$4.07.

2 The Lakehead System Local Toll is per barrel of heavy crude oil transported from Neche, North Dakota to Chicago, Illinois. Effective April 1, 2016, this toll increased to US$2.61 and effective July 1, 2016, this toll decreased to US$2.58. Effective April 1, 2017, this toll decreased to US$2.43.

3 The Canadian Mainline IJT Residual Benchmark Toll is per barrel of heavy crude oil transported from Hardisty, Alberta to Gretna, Manitoba. For any shipment, this toll is the difference between the IJT Benchmark Toll and the Lakehead System Local Toll. Effective April 1, 2016, this toll decreased to US$1.46, coinciding with the revised Lakehead System Local Toll. Effective July 1, 2016, this toll increased to US$1.47. Effective April 1, 2017, this toll increased to US$1.62, coinciding with the revised Lakehead System Local Toll. Effective July 1, 2017, this toll increased to US$1.64.

Throughput Volume

Three months ended


September 30, 2017 2016 2017 2016 (thousands of bpd) Average throughput volume1 2,492 2,353 2,511 2,379

1 Throughput volume represents mainline deliveries ex-Gretna, Manitoba which is made up of United States and eastern Canada deliveries originating from western Canada.

Lakehead System Lakehead System adjusted EBIT decreased in the third quarter of 2017, compared with the corresponding 2016 period, primarily due to a lower average Lakehead System Local Toll, increased property taxes and higher depreciation expense due to growth, and hydrostatic testing costs in the third quarter of 2017. These negative impacts were further increased by a lower Average Exchange Rate in the third quarter of 2017, compared with the corresponding 2016 period. Higher average throughput for the three months ended September 30, 2017, compared with the corresponding 2016 period, partially offset these negative impacts. Lakehead System adjusted EBIT decreased for the nine months ended September 30, 2017, compared with the corresponding 2016 period, primarily due to the same factors discussed above for the third quarter of 2017; however, the average Lakehead System Local Toll for the first half of 2017 was comparable to the corresponding 2016 period. As discussed under Canadian Mainline above, higher throughput on the Lakehead System for the three and nine months ended September 30, 2017, compared with the corresponding 2016 periods, reflected strong downstream demand as well as the capacity optimization initiatives enabled in the third quarter of 2017. Throughput for the nine months ended September 30, 2017, was higher than the corresponding 2016 period, partially driven by the negative impact of the northeastern Alberta wildfires experienced in 2016. The wildfires resulted in a curtailment of production from oil sands facilities and the temporary shutdown of certain of the Company's upstream pipelines and terminal facilities, decreasing Lakehead System adjusted EBIT by approximately $38 million for the nine months ended September 30, 2016. Throughput for the first nine months of 2017 was partially offset by lower deliveries from the Canadian Mainline as a result of the unexpected outage and accelerated maintenance at a customer's upstream facility, additional related and unrelated production disruptions, and a hydrostatic testing program on Line 5 during the month of June 2017.


Excluding the impact of foreign exchange translation to Canadian dollars, Lakehead System adjusted EBIT was US$230 million and US$746 million for the three and nine months ended September 30, 2017, respectively, compared with US$255 million and US$790 million for corresponding 2016 periods. As noted above, further impacting the three and nine months ended September 30, 2017 decrease in Lakehead System adjusted EBIT was the unfavourable effect of translating United States dollar earnings at a lower Average Exchange Rate, compared with the corresponding 2016 periods. A portion of Lakehead System United States dollar EBIT is hedged as part of the Company’s enterprise-wide financial risk management program. The Company uses foreign exchange derivative instruments to manage the foreign exchange risk arising from its United States businesses including the Lakehead System. Realized gains and losses from these derivative instruments are reported within Eliminations and Other. For further details refer to Eliminations and Other. Throughput Volume

Three months ended


September 30, 2017 2016 2017 2016 (thousands of bpd) Average throughput volume1 2,620 2,495 2,657 2,558

1 Throughput volume represents mainline system deliveries to the United States midwest and eastern Canada.

Average Exchange Rate

Three months ended


September 30, 2017 2016 2017 2016 Average Exchange Rate (U.S. dollar to Canadian dollar) 1.25 1.31 1.31 1.32

Mid-Continent and Gulf Coast Mid-Continent and Gulf Coast adjusted EBIT decreased for the three and nine months ended September 30, 2017, compared with the corresponding 2016 periods, primarily due to lower contributions from Flanagan South Pipeline (Flanagan South) and the disposition of the Ozark Pipeline. The decrease in adjusted EBIT was further impacted by a lower Average Exchange Rate for the three and nine months ended September 30, 2017, compared with the corresponding 2016 periods. Excluding the impact of foreign exchange translation to Canadian dollars, Mid-Continent and Gulf Coast adjusted EBIT was US$105 million and US$290 million for the three and nine months ended September 30, 2017, respectively, compared with US$125 million and US$382 million for the three and nine months ended September 30, 2016. Mid-Continent and Gulf Coast adjusted EBIT for prior periods included make-up rights adjustments to recognize revenue for certain long-term take-or-pay contracts rateably over the contract life. When committed shippers on Flanagan South are unable to fulfill their volume commitments due to apportionment, they are provided with temporary relief to make up those volumes during the course of their contracts or the apportioned volumes are added on to the end of the contract term. Due to upstream mainline apportionment, committed shippers on Flanagan South were provided higher apportionment relief in the first half of 2017, compared with the first half of 2016, which resulted in lower contractual cash payments from these shippers. For the purposes of determining adjusted EBIT, prior to January 1, 2017, the Company reflected contributions from these contracts rateably over the life of the contract, consistent with contractual cash payments under the contract. Effective January 1, 2017, for the purposes of determining adjusted EBIT, the Company discontinued this treatment. This factor was less pronounced in the third quarter of 2017, as throughput volumes and deferred revenue recognized were both higher and therefore, offset the 2016 adjustment recorded in EBIT for contractual cash payments.


As noted above, further impacting the three and nine months ended September 30, 2017 decrease in adjusted EBIT was the unfavourable effect of translating United States dollar earnings at a lower Average Exchange Rate compared with the corresponding 2016 periods. Similar to the Lakehead System, a portion of Mid-Continent and Gulf Coast United States dollar EBIT is hedged as part of the Company’s enterprise-wide financial risk management program, and realized gains and losses from the derivative instruments used to hedge foreign exchange risk arising from the Company’s investment in United States businesses are reported within Eliminations and Other. For further details refer to Eliminations and Other. Express-Platte System The Express-Platte system is comprised of both the Express pipeline and the Platte pipeline, and crude oil storage of approximately 5.6 million barrels. It is an approximate 2,736 kilometre (1,700 mile) crude oil transportation system, which begins in Hardisty, Alberta, and terminates in Wood River, Illinois. The Express pipeline carries crude oil to United States refining markets in the Rockies area, including Montana, Wyoming, Colorado and Utah. The Platte pipeline, which interconnects with the Express pipeline in Casper, Wyoming, transports crude oil predominantly from the Bakken shale and western Canada to refineries in the Midwest. The Company has a 75% indirect ownership interest in the Express-Platte system, through its investment in SEP. Express pipeline capacity is typically committed under long-term take-or-pay contracts with shippers. A small portion of Express pipeline capacity and all of the Platte pipeline capacity is used by uncommitted shippers who pay only for the pipeline capacity they actually use in a given month. The Express-Platte system is exposed to the same business risks as the Company’s other Liquids Pipelines assets as discussed in Enbridge’s MD&A for the year ended December 31, 2016. Results of Operations Express-Platte adjusted EBIT for the three and nine months ended September 30, 2017, reflects results of operations since the completion of the Merger Transaction. When compared to pre-merger results from the prior year, Express-Platte results reflect higher crude oil transportation revenues due to higher uncommitted volumes on the Express pipeline, higher tariff rates on the Express pipeline due to annual escalations, and higher volumes from the Express Enhancement expansion project placed into service in October 2016. These higher revenues were partially offset by higher power costs due to higher throughput. Feeder Pipelines and Other Feeder Pipelines and Other adjusted EBIT decreased for the three and nine months ended September 30, 2017, compared with the corresponding 2016 periods, reflecting the absence of EBIT from the South Prairie Region assets that were sold in December 2016.


GAS PIPELINES AND PROCESSING Earnings Before Interest and Income Taxes

Three months ended



US Gas Transmission1 537 — 1,311 —

Canadian Midstream2 67 28 170 77

Alliance Pipeline 49 48 149 144

US Midstream3,4 27 (3 ) 3 1

Other5 20 21 70 49

Adjusted earnings before interest and income taxes 700 94 1,703 271

US Gas Transmission - pipeline inspection and other compliance costs (23) —

(39) —

US Gas Transmission - project development and transaction costs (1) —

(4) —

Canadian Midstream - project development and transaction costs —

—

(1) —

Canadian Midstream - transition costs (5) — (5) —

Canadian Midstream - Grizzly Valley flood (3) — 4 —

Alliance Pipeline - changes in unrealized derivative fair value gain/(loss) 2

(1 ) 7

11

US Midstream - changes in unrealized derivative fair value loss (22) (19 ) —

(116 )

US Midstream - DCP Midstream equity earnings adjustment (25) —

(21) —

US Midstream - transition costs (5) — (5) —

US Midstream - assets impairment loss — (3 ) — (14 ) US Midstream - loss on sale of non-core assets and

investments, net —

(4 ) —

(4 )

US Midstream - make-up rights adjustment — — — (1 ) Other - transition costs (3) — (3) —

Earnings before interest and income taxes 615 67 1,636 147

1 Includes adjusted EBIT from US Gas Transmission since the completion of the Merger Transaction. For additional information, refer to Merger with Spectra Energy.

2 Includes adjusted EBIT from British Columbia Pipeline & Field Services, Spectra Canadian Midstream, Maritimes & Northeast Pipeline Limited Partnership (M&N Canada) and certain other gas pipeline, gathering and storage assets since the completion of the Merger Transaction.

3 Includes adjusted EBIT from DCP Midstream since the completion of the Merger Transaction. 4 Effective January 1, 2017, adjusted EBIT from Aux Sable, which is comprised of Enbridge’s equity interest in Aux Sable US, Aux

Sable Midstream US and Aux Sable Canada, has been grouped with US Midstream. Comparative amounts have been reclassified to facilitate comparison.

5 Effective January 1, 2017, adjusted EBIT from Vector Pipeline and Enbridge Offshore Pipelines (Offshore) have been grouped with Other. Comparative amounts have been reclassified to facilitate comparison.

Additional details on items impacting Gas Pipelines and Processing EBIT include:

• US Midstream EBIT for each period reflects changes in unrealized fair value gains and losses on derivative financial instruments used to risk manage commodity price exposures.


US Gas Transmission The assets that comprise US Gas Transmission were acquired through the Merger Transaction and consist of natural gas transmission and storage assets that are held through SEP. US Gas Transmission includes indirect ownership interests in Texas Eastern, Algonquin, East Tennessee Natural Gas, M&N U.S., Gulfstream, Sabal Trail, and certain other gas pipeline, gathering and storage assets. The US Gas Transmission business primarily provides transmission, storage and gathering of natural gas through interstate pipeline systems for customers in various regions of the midwestern, northeastern and southern United States and in Canada. The Texas Eastern natural gas transmission system extends approximately 2,735 kilometres (1,700 miles) from producing fields in the Gulf Coast region of Texas and Louisiana to Ohio, Pennsylvania, New Jersey and New York. Texas Eastern's onshore system consists of approximately 14,000 kilometres (8,700 miles) of pipeline and associated compressor stations. Texas Eastern is also connected to four affiliated storage facilities that are partially or wholly-owned by other entities within the US Gas Transmission business. The Algonquin natural gas transmission system connects with Texas Eastern’s facilities in New Jersey and extends approximately 402 kilometres (250 miles) through New Jersey, New York, Connecticut, Rhode Island and Massachusetts where it connects to M&N U.S. The system consists of approximately 1,819 kilometres (1,130 miles) of pipeline with associated compressor stations. East Tennessee’s natural gas transmission system crosses Texas Eastern’s system at two locations in Tennessee and consists of two mainline systems totalling approximately 2,414 kilometres (1,500 miles) of pipeline in Tennessee, Georgia, North Carolina and Virginia, with associated compressor stations. East Tennessee has a Liquefied Natural Gas (LNG) storage facility in Tennessee and also connects to the Saltville storage facilities in Virginia. M&N U.S. is an approximately 563 kilometre (350 mile) mainline interstate natural gas transmission system, including associated compressor stations, which extends from the border of Canada near Baileyville, Maine to northeastern Massachusetts. M&N U.S. is connected to the Canadian portion of the Maritimes & Northeast Pipeline system, M&N Canada (see Gas Pipelines and Processing – Canadian Midstream). Gulfstream is an approximately 1,199 kilometre (745 mile) interstate natural gas transmission system, with associated compressor stations, operated jointly by SEP and The Williams Companies, Inc. Gulfstream transports natural gas from Mississippi, Alabama, Louisiana and Texas, crossing the Gulf of Mexico to markets in central and southern Florida. Gulfstream is accounted for under the equity method of accounting. Sabal Trail was placed into service in early July 2017. For further discussion, refer to Growth Projects - Commercially Secured Projects - Gas Pipelines and Processing - Sabal Trail. Transmission and storage services are generally provided under firm agreements where customers reserve capacity in pipelines and storage facilities. The vast majority of these agreements provide for fixed reservation charges that are paid monthly regardless of the actual volumes transported on the pipelines or injected or withdrawn from the Company’s storage facilities, plus a small variable component that is based on volumes transported, injected or withdrawn, which is intended to recover variable costs. Interruptible transmission and storage services are also available where customers can use capacity if it exists at the time of the request. Interruptible revenues depend on the amount of volumes transported or stored and the associated rates for this service. Storage operations also provide a variety of other value-added services including natural gas parking, loaning and balancing services to meet customers’ needs.


Business Risks The risks identified below are specific to US Gas Transmission. General risks that affect the entire Company are described under Risk Management and Financial Instruments – General Business Risks in Enbridge’s MD&A for the year ended December 31, 2016. Asset Utilization Gas supply and demand dynamics continue to change as a result of the development of non-conventional shale gas supplies. The increase in natural gas supply has resulted in declines in the price of natural gas in North America. As a result, a shift occurred to extraction of gas in richer, “wet” gas areas with higher NGL content which depressed activity in “dry” fields. This, in turn, has contributed to a resulting oversupply of pipeline takeaway capacity in some areas. Seasonal Price Spreads The supply increase has also had a negative impact on the seasonal price spreads historically seen between the summer and winter months. The value of storage assets and contracts has declined in recent years, negatively affecting the results from the Company’s storage facilities. Economic Regulation US Gas Transmission is subject to laws and regulations at the federal and state levels. Regulations applicable to the natural gas transmission and storage industries have a significant effect on the nature of the businesses and the manner in which they operate. Changes to regulations are ongoing and the Company cannot predict the future course of changes in the regulatory environment or the ultimate effect that any future changes will have on its businesses. Competition The US Gas Transmission business competes with similar facilities that serve the same supply and market areas in the transmission and storage of natural gas. The principal elements of competition are location, rates, terms of service, flexibility and reliability of service. The natural gas transported in the US Gas Transmission business also competes with other forms of energy available to the Company’s customers and end-users, including electricity, coal, propane and fuel oils. Results of Operations US Gas Transmission adjusted EBIT for the three and nine months ended September 30, 2017, reflected results of operations since the completion of the Merger Transaction. When compared to pre-merger results from the prior year, US Gas Transmission’s operating results include higher earnings primarily from business expansion projects on Algonquin Gas Transmission, Sabal Trail Transmission and Texas Eastern Transmission. Canadian Midstream Upon completion of the Merger Transaction, Canadian Midstream now includes the Western Canada Transmission & Processing businesses, which comprise British Columbia Pipeline & Field Services, Canadian Midstream, M&N Canada and certain other gas pipeline, gathering and storage assets. British Columbia Pipeline and British Columbia Field Services provide fee-based natural gas transmission and gas gathering and processing services. British Columbia Pipeline has approximately 2,816 kilometres (1,750 miles) of transmission pipeline in British Columbia and Alberta, as well as associated mainline compressor stations. The British Columbia Field Services business includes eight gas processing plants located in British Columbia associated field compressor stations and approximately 2,253 kilometres (1,400 miles) of gathering pipelines. Canadian Midstream provides similar gas gathering and processing services in British Columbia and Alberta and consists of nine natural gas processing plants and approximately 966 kilometres (600 miles) of gathering pipelines. M&N Canada is an approximately 885 kilometre (550 mile) interprovincial natural gas transmission mainline system which extends from Goldboro, Nova Scotia to the United States border near Baileyville, Maine. M&N Canada is connected to M&N U.S. – refer to Gas Pipelines and Processing - US Gas Transmission.


The majority of transportation services provided by British Columbia Pipeline are under firm agreements, which provide for fixed reservation charges that are paid monthly regardless of actual volumes transported on the pipeline, plus a small variable component that is based on volumes transported to recover variable costs. British Columbia Pipeline also provides interruptible transmission services where customers can use capacity if it is available at the time of request. Payments under these services are based on volumes transported. Natural gas gathering and processing services are provided under fee-for-service contracts. Business Risks The risks identified below are specific to the Western Canada Transmission & Processing businesses. General risks that affect the entire Company are described under Risk Management and Financial Instruments – General Business Risks in Enbridge’s MD&A for the year ended December 31, 2016. Competition Western Canada Transmission & Processing businesses compete with third-party midstream companies, producers and pipelines in the gathering, processing and transmission of natural gas. The principal elements of competition are location, rates, terms of service, and flexibility and reliability of service. Asset Utilization Western Canada Transmission & Processing businesses provide services under fee-for-service contracts and its revenues are not directly exposed to commodity price risk. However, the sustained decline in natural gas prices has reduced producer demand for both expansions of the British Columbia gas processing plants as well as renewals of existing gas processing contracts, and this trend could continue if prices remain below historical norms. Results of Operations Canadian Midstream adjusted EBIT for the three and nine months ended September 30, 2017, reflected the results of operations from the new assets acquired through the Merger Transaction as described above. The three and nine months ended September 30, 2017 increase in Canadian Midstream adjusted EBIT also reflected contributions from the Tupper Plants acquired in April 2016. When compared to pre-merger results from the corresponding periods in 2016, Canadian Midstream results include a decrease in committed revenue primarily as a result of shipper contract renewals at lower volumes as well as an increase in operating and maintenance costs, partially offset by higher interruptible revenues and incremental revenues from volumes that exceeded take-or-pay levels due to robust producer activity within Canadian Midstream’s footprint. Alliance Pipeline Alliance Pipeline adjusted EBIT for the three and nine months ended September 30, 2017, which comprises equity earnings from the Company’s 50% equity investment in Alliance Pipeline, was comparable with the corresponding 2016 periods. US Midstream Upon completion of the Merger Transaction, US Midstream now also includes a 50% investment in DCP Midstream, which is accounted for as an equity investment. DCP Midstream gathers, compresses, treats, processes, transports, stores and sells natural gas. It also produces, fractionates, transports, stores and sells NGLs, recovers and sells condensate, and trades and markets natural gas and NGLs. Phillips 66 owns the other 50% interest in DCP Midstream. DCP Midstream is exposed to similar business risks as the Company’s existing US Midstream assets as disclosed in Enbridge’s MD&A for the year ended December 31, 2016.


Purchase, Service and Sales Agreements DCP Midstream sells a portion of its NGLs to Phillips 66 and Chevron Phillips Chemical Company LLC (CPChem). In addition, DCP Midstream purchases NGLs from CPChem. Approximately 26% of DCP Midstream’s NGL production was committed to Phillips 66 and CPChem as at September 30, 2017, under contracts expiring in January 2019. DCP Midstream anticipates continuing to purchase and sell commodities with Phillips 66 and CPChem, in the ordinary course of business. The residual natural gas, primarily methane, that results from processing raw natural gas is sold at market-based prices to marketers and end-users, including large industrial companies, natural gas distribution companies and electric utilities. DCP Midstream purchases or takes custody of substantially all of its raw natural gas from producers, principally under percentage-of-proceeds/index arrangements, keep-whole and wellhead purchase agreements, and fee-based arrangements. More than 75% of the volumes of gas that are gathered and processed are under percentage-of-proceeds contracts. Percentage-of-proceeds arrangements typically result in DCP Midstream gathering, processing and selling natural gas that has been purchased from producers. The residue natural gas and NGLs are sold based on index prices from published index market prices. DCP Midstream remits to the producers either an agreed-upon percentage of the actual proceeds received by DCP Midstream or an agreed-upon percentage of the proceeds based on index-related prices or receives a base fee. DCP Midstream’s revenues from percentage-of-proceeds/index arrangements are directly related to the prices of natural gas, NGLs or condensate. Results of Operations US Midstream, excluding adjusted EBIT from DCP Midstream, incurred a higher adjusted loss before interest and income taxes for the three and nine months ended September 30, 2017, compared with the corresponding 2016 periods. The increase in adjusted loss before interest and income taxes for the three and nine months ended September 30, 2017, was primarily attributable to lower volumes on the Company’s US Midstream assets that are held by MEP, as a result of the continued low commodity price environment which resulted in reduced drilling by producers. In addition, US Midstream third-party contracts held by MEP experienced higher unutilized transportation and fractionation fees. Partially offsetting this negative effect was higher contributions from Aux Sable US due to increased fractionation margins. Post completion of the Merger Transaction, DCP Midstream contributed $36 million and $64 million to US Midstream adjusted EBIT for the three and nine months ended September 30, 2017, respectively. Other Other adjusted EBIT increased for the nine months ended September 30, 2017, compared with the corresponding 2016 period, primarily reflecting positive contributions from Offshore as a result of an increase in volumes on Heidelberg Oil Pipeline and an increase in variable rate revenues on the Walker Ridge Gas Gathering System.


GAS DISTRIBUTION Earnings Before Interest and Income Taxes

Three months ended



Enbridge Gas Distribution Inc. (EGD) 31 30 250 277

Union Gas Limited (Union Gas)1 42 — 184 —

Noverco Inc. (Noverco) 6 2 30 35

Other Gas Distribution and Storage 2 (1 ) 39 32

Adjusted earnings before interest and income taxes 81 31 503 344

EGD - warmer than normal weather2 — — — (8 ) Noverco - changes in unrealized derivative fair value

gain/(loss) 3

(6 ) 13

(6 )

Noverco - asset impairment — (5 ) — (5 ) Noverco - recognition of regulatory balances — — — 17

Union Gas - employee severance and restructuring costs (1) —

(5) —

Earnings before interest and income taxes 83 20 511 342

1 Includes adjusted EBIT from Union Gas since the completion of the Merger Transaction. For additional information, refer to Merger with Spectra Energy.

2 Effective January 1, 2017, the Company no longer adjusts for the impact of weather in the determination of its adjusted EBIT.

EGD As EGD’s operations are rate-regulated and its revenues are directly impacted by items such as depreciation, financing charges and current income taxes, the adjusted EBIT measure for EGD is less indicative of business performance. In light of the nature of the regulated model for EGD’s business, the following supplemental adjusted earnings information is provided to facilitate an understanding of EGD’s results from operations: EGD Earnings

Three months ended


September 30,

2017 2016 2017 2016 (millions of Canadian dollars)

Adjusted earnings before interest and income taxes 31 30 250 277

Interest expense (47) (50 ) (137) (131 ) Income taxes 9 14 3 (6 ) Adjusting items in respect of:

Interest expense — 3 1 3

Income taxes — (1 ) — (3 ) Adjusted earnings/(loss) (7) (4 ) 117 140

EGD - warmer than normal weather — — — (6 ) EGD - changes in unrealized derivative fair value loss — (2 ) — (2 ) Earnings/(loss) attributable to common shareholders (7) (6 ) 117 132

EGD adjusted loss for the three months ended September 30, 2017, was comparable with the corresponding 2016 period. EGD adjusted earnings decreased for the nine months ended September 30, 2017, compared with the corresponding 2016 period, primarily due to higher earnings sharing in 2017, higher depreciation expense resulting from a higher overall asset base and lower capitalized interest due to the completion of the Greater Toronto Area project in March 2016, partially offset by lower employee and pension related costs.


Adjusted earnings for EGD was also lower for the nine months ended September 30, 2017, relative to the comparable period in 2016, as a result of a change in practice with respect to weather normalization. Prior to January 1, 2017, the impacts of warmer/colder than normal weather were removed for the purposes of EGD adjusted earnings. Effective January 1, 2017, the Company discontinued this practice, and as such, EGD adjusted earnings reflected lower distribution revenues due to the impacts of warmer than normal weather during the three and nine months ended September 30, 2017. If the Company had continued with the above noted weather normalization treatment, EGD adjusted earnings would have increased by $23 million, for the nine months ended September 30, 2017. Union Gas Union Gas is a major Canadian natural gas storage, transmission and distribution company based in Ontario with over 100 years of operations and service to customers. The distribution business serves approximately 1.5 million residential, commercial and industrial customers in more than 400 communities across northern, southwestern and eastern Ontario. Union Gas’ storage and transmission business offers storage and transmission services to customers at the Dawn Hub, the largest integrated underground storage facility in Canada and one of the largest in North America. It offers customers an important link in the movement of natural gas from western Canada and United States supply basins to markets in central Canada and the northeast United States. Union Gas’ distribution system consists of approximately 64,374 kilometres (40,000 miles) of main and service pipelines. Union Gas’ underground natural gas storage facilities have a working capacity of approximately 165 billion cubic feet in 25 underground facilities located in depleted gas fields. Its transmission system consists of approximately 4,828 kilometres (3,000 miles) of high pressure pipeline and associated mainline compressor stations. As with EGD, Union Gas’ distribution system is regulated by the Ontario Energy Board (OEB) and is subject to regulation in a number of areas, including rates. Union Gas provides its in-franchise customers with regulated distribution, transmission and storage services and also provides unregulated natural gas storage and regulated transmission services for other utilities and energy market participants, including large natural gas transmission and distribution companies. A substantial amount of Union Gas’ annual transportation and storage revenue is generated by fixed demand charges. Incentive Regulation Framework Union Gas’ distribution rates are set under a five-year incentive regulation framework. The incentive regulation framework establishes new rates at the beginning of each year through the use of a pricing formula rather than through the examination of revenue and cost forecasts. The framework allows for:

• annual inflationary rate increases, offset by a productivity factor of 60% of inflation, such that the annual net rate escalator in each year is 40% of inflation;

• rate increases or decreases in the small volume customer classes where average use declines or increases;

• certain adjustments to rates; • the continued pass-through of gas commodity, upstream transportation and demand side

management costs; • the additional pass-through of costs associated with major capital investments and certain fuel

variances; • an allowance for unexpected cost changes that are outside of management’s control; • equal sharing of tax changes between Union Gas and customers; and • an earnings sharing mechanism that permits Union Gas to fully retain the return on equity from

utility operations up to 9.93%, share 50% of any earnings between 9.93% and 10.93% with customers, and share 90% of any earnings above 10.93% with customers. In October 2016, Union Gas filed an application with the OEB for new rates effective January 1, 2017, pursuant to the incentive regulation framework. In December 2016, the OEB approved the application on an interim basis with an implementation date of January 1, 2017, to be included in the Quarterly Rate


Adjustment Mechanism. A final rate order is expected after the OEB completes its review of Union Gas’ Cap and Trade Compliance Plan.

Cap and Trade Similar to EGD, Union Gas is subject to the requirements of the Government of Ontario’s Cap and Trade program, which became effective January 1, 2017. Refer to Gas Distribution – Enbridge Gas Distribution Inc. – Cap and Trade in Enbridge’s MD&A for the year ended December 31, 2016, for more information on this program. In November 2016, Union Gas filed its 2017 Compliance Plan and the OEB issued an interim rate order approving the associated Cap and Trade costs for recovery from customers effective January 1, 2017. In September 2017 the OEB issued its Decision and Order on both Union Gas' 2017 Compliance Plan and EGD’s 2017 Compliance Plan. The OEB noted in its Decision and Order that both plans were based on reasonable option analysis, optimized decision-making and risk management process and analysis. Final rate approval from the OEB is expected by the end of 2017. Business Risks Union Gas is subject to substantially the same business risks as Enbridge’s other gas distribution assets as disclosed in Enbridge’s MD&A for the year ended December 31, 2016. Results of Operations Union Gas’ adjusted EBIT for the three and nine months ended September 30, 2017, reflects its results of operations since the completion of the Merger Transaction. When compared to pre-merger results from the prior year, Union Gas’ operating results benefitted mainly from higher transportation revenue from the Dawn-Parkway expansion project and increases in delivery rates, partially offset by higher operating costs. As Union Gas’ operations are rate-regulated and its revenues are directly impacted by items such as depreciation, financing charges and current income taxes, the adjusted EBIT measure for Union Gas is less indicative of business performance. In light of the nature of the regulated model for Union Gas’ business, the following supplemental adjusted earnings information is provided to facilitate an understanding of Union Gas’ results from operations: Union Gas Earnings1

Three months ended September 30, 2017

Nine months ended September 30, 2017

(millions of Canadian dollars)

Adjusted earnings before interest and income taxes 42 184

Interest expense (43) (99) Income taxes (2) 9

Adjusting items in respect of: Income taxes — (1)

Earnings attributable to noncontrolling interests (1) (2) Adjusted earnings/(loss) (4) 91

Union Gas - Employee severance and restructuring costs — (3) Earnings/(loss) attributable to common shareholders (4) 88

1 Includes adjusted earnings generated by Union Gas since the completion of the Merger Transaction.

Similar to EGD, Union Gas’ adjusted earnings for each period include the impact of warmer/colder than normal weather in their franchise area. If Union Gas made an adjustment for warmer than normal weather, adjusted earnings would have decreased by $2 million and increased by $7 million, for the three and nine months ended September 30, 2017, respectively.


GREEN POWER AND TRANSMISSION Earnings Before Interest and Income Taxes

Three months ended




Adjusted earnings before interest and income taxes 20 34 121 122 Green Power and Transmission - changes in

unrealized derivative fair value gain —

— —

2

Earnings before interest and income taxes 20 34 121 124

Green Power and Transmission adjusted EBIT decreased for the three months ended September 30, 2017, compared with the corresponding 2016 period. The decrease in adjusted EBIT reflected weaker Canadian and United States wind resources, and higher business development costs. Green Power and Transmission adjusted EBIT for the nine months ended September 30, 2017, was comparable with the corresponding 2016 period. ENERGY SERVICES Earnings Before Interest and Income Taxes

Three months ended



Energy Services (24) (15 ) (32) 33

Adjusted earnings/(loss) before interest and income taxes (24) (15 ) (32) 33

Energy Services - changes in unrealized derivative fair value gain/(loss) (124) (10 ) 22

(71 )

Energy Services - transition costs (2) — (2) —

Loss before interest and income taxes (150) (25 ) (12) (38 )

Following are additional details on items impacting Energy Services EBIT:

• Energy Services EBIT for each period reflects changes in unrealized fair value gains and losses related to the revaluation of financial derivatives used to manage the profitability of transportation and storage transactions and exposure to movements in commodity prices on the value of inventory.

Energy Services adjusted EBIT for the three and nine months ended September 30, 2017 reflected compressed basis differentials in certain markets and fewer opportunities to achieve profitable margins on facilities which hold capacity obligations. Opportunities to generate positive margins were particularly affected in the third quarter of 2017 by the impact of the hurricanes on commodity prices and differentials. Adjusted EBIT from Energy Services is dependent on market conditions and results achieved in one period may not be indicative of results to be achieved in future periods.


ELIMINATIONS AND OTHER Earnings Before Interest and Income Taxes

Three months ended



Operating and administrative (6) (22 ) (84) (56 ) Realized foreign exchange derivative loss (17) (69 ) (159) (220 ) Other 8 7 30 23

Adjusted loss before interest and income taxes (15) (84 ) (213) (253 ) Changes in unrealized derivative fair value gain 161 29 416 434 Unrealized intercompany foreign exchange gain/(loss) (6) 2 (20) (53 ) Project development and transaction costs — (27 ) (195) (27 ) Employee severance and restructuring costs (39) (22 ) (243) (30 ) Earnings/(loss) before interest and income taxes 101 (102 ) (255) 71

Items impacting Eliminations and Other EBIT include:

• Changes in unrealized fair value gains on derivative financial instruments used to manage foreign exchange risk.

• Project development and transaction costs incurred in 2017 in relation to the Merger Transaction. For additional information, refer to Merger with Spectra Energy.

• Employee severance and restructuring costs incurred in 2017. Eliminations and Other also reflects a portion of the synergies achieved thus far on integration of corporate functions. For the three and nine months ended September 30, 2017, realized foreign exchange derivative losses decreased by $52 million and $61 million, respectively, compared with the corresponding 2016 periods. The realized loss related to settlements under the Company’s foreign exchange risk management program. The Company targets to hedge 80% or more of anticipated consolidated United States dollar denominated earnings from its United States operations utilizing foreign exchange derivative contracts with the objective of enhancing the predictability of its Canadian dollar earnings. Supplemental information related to the foreign exchange risk management program for the three and nine months ended September 30, 2017 and 2016 is provided below:

Three months ended


September 30, 2017 2016 2017 2016 (millions of U.S. dollars, except exchange rates)

Foreign currency derivatives realized - notional amount 434 261 1,018 783

Average hedge rate 1.21 1.04 1.14 1.04 Average Exchange Rate (U.S. dollar to Canadian dollar) 1.25 1.31 1.31 1.32

As the hedged rate was lower than the Average Exchange Rate in each of the three and nine-month periods in 2017 and 2016, the Company recognized a realized hedge loss in each of these periods. The realized hedge loss for the three and nine months ended September 30, 2017, was less than the comparative 2016 periods due to lower unfavourable spread between the Average Exchange Rate and hedged rate. The realized loss in Eliminations and Other partially offsets the positive effect of translating the earnings performance of United States dollar denominated businesses at a higher Average Exchange Rate which is reflected in the reported EBIT of the applicable business segments.


Realized gains and losses on this hedging program are reported in their entirety within Eliminations and Other as the Company manages the foreign exchange risk of its United States businesses at an enterprise-wide level. Gains and losses arising on settlements of foreign exchange derivatives hedging transactional exposure arising from foreign denominated revenues or expenses within the Company’s Canadian businesses are captured at the business level and reported as part of the EBIT of the applicable segment. For example, gains and losses on hedges of the Canadian Mainline’s United States denominated revenue are reported as part of the EBIT from Canadian Mainline.

GROWTH PROJECTS – COMMERCIALLY SECURED PROJECTS The following table summarizes the status of the Company’s commercially secured projects, organized by business segment. Expenditures to date reflect total cumulative expenditures incurred from inception of the project to September 30, 2017.

Estimated Capital Cost1

Expenditures to Date

Expected In-Service

Date Status

(Canadian dollars, unless stated otherwise)

LIQUIDS PIPELINES 1. Norlite Pipeline System (the Fund

Group) $1.3 billion $1.1 billion 2017 Complete

2. Bakken Pipeline System (EEP) US$1.5 billion US$1.5 billion 2017 Complete 3. Regional Oil Sands Optimization

Project (the Fund Group) $2.6 billion $2.3 billion 2017

(in phases) Substantially

complete 4. Lakehead System Mainline

Expansion - Line 61 (EEP) US$0.4 billion US$0.4 billion 2019 Substantially

complete 5. Canadian Line 3 Replacement

Program (the Fund Group) $5.3 billion $1.9 billion 2019 Under

construction 6. U.S. Line 3 Replacement

Program (EEP) US$2.9 billion US$0.6 billion 2019 Under

construction 7. Other - Canada $0.3 billion $0.1 billion 2017-2018 Various

stages GAS PIPELINES AND PROCESSING 8. Sabal Trail (SEP)2 US$1.6 billion US$1.5 billion 2017 Complete 9. Access South, Adair Southwest

and Lebanon Extension (SEP)2 US$0.5 billion US$0.3 billion 2017 Substantially

complete 10. Atlantic Bridge (SEP)2 US$0.5 billion US$0.3 billion 2017-2018 Under

construction 11. NEXUS (SEP)2

US$1.3 billion US$0.5 billion 2018 Under

construction 12. High Pine2 $0.4 billion $0.3 billion 2018 Under

construction 13. Reliability and Maintainability

Project2 $0.5 billion $0.3 billion 2017-2018 Under

construction 14. Valley Crossing Pipeline2 US$1.5 billion US$0.9 billion 2018 Under

construction 15. Spruce Ridge Program2 $0.5 billion No significant

expenditures to date 2019 Pre-

construction 16. T-South Expansion Program2

$1.0 billion No significant

expenditures to date 2020 Pre-

construction 17. Other - United States2 US$1.7 billion US$0.9 billion 2017-2019 Various

stages 18. Other - Canada2 $0.4 billion $0.2 billion 2017-2018 Various

stages


Estimated Capital Cost1

Expenditures to Date

Expected In-Service

Date Status

(Canadian dollars, unless stated otherwise) GAS DISTRIBUTION 19. 2017 Dawn-Parkway Expansion2 $0.6 billion $0.6 billion 2017 Complete

20. Other - Canada2 $0.3 billion $0.2 billion 2017 Complete

GREEN POWER AND TRANSMISSION 21. Chapman Ranch Wind Project US$0.4 billion US$0.3 billion 2017 Complete

22. Rampion Offshore Wind Project $0.8 billion (£0.37 billion)

$0.5 billion (£0.3 billion)

2018 Under construction

23. Hohe See Offshore Wind Project $1.7 billion (€1.07 billion)

$0.5 billion (€0.4 billion)

2019 Pre- construction

24. Hohe See Expansion Project $0.4 billion (€0.27 billion)

No significant expenditures to date

2019 Pre- construction

1 These amounts are estimates and are subject to upward or downward adjustment based on various factors. Where appropriate, the amounts reflect Enbridge’s share of joint venture projects.

2 Includes projects acquired as part of the Merger Transaction. For additional information, refer to Merger with Spectra Energy.

The description of each of the Enbridge projects, including those being undertaken by EEP and the Fund Group, which is comprised of the Fund, Enbridge Commercial Trust, Enbridge Income Partners LP (EIPLP) and the subsidiaries and investees of EIPLP, is provided in the Company’s 2016 annual MD&A. Projects where significant developments have occurred since February 17, 2017, the date of the filing of the Company’s MD&A for the year ended December 31, 2016, including the commercially secured growth projects acquired upon close of the Merger Transaction, are discussed below. LIQUIDS PIPELINES Norlite Pipeline System (the Fund Group) Norlite Pipeline System, a diluent pipeline originating from the Company’s Stonefell Terminal, was placed into commercial service on May 1, 2017. To meet the needs of multiple producers in the Athabasca oil sands region, the 24-inch diameter pipeline provides an initial capacity of approximately 218,000 Barrels per day (bpd) of diluent, with the potential to be further expanded to approximately 465,000 bpd of capacity with the addition of pump stations. Keyera Corp. has elected to participate in the Norlite Pipeline System as a 30% non-operating owner. Bakken Pipeline System (EEP) On February 15, 2017, EEP acquired an effective 27.6% interest in the Bakken Pipeline System for a purchase price of $2.0 billion (US$1.5 billion). The Bakken Pipeline System was placed into service on June 1, 2017. It connects the Bakken formation in North Dakota to markets in the eastern Petroleum Administration for Defense Districts and the United States Gulf Coast. On April 27, 2017, Enbridge entered into a joint funding arrangement with EEP whereby Enbridge owns 75% and EEP owns 25% of the combined 27.6% effective interest in the Bakken Pipeline System. Lakehead System Mainline Expansion (EEP) The Lakehead System Mainline Expansion includes several projects to expand capacity of the Lakehead Pipeline System (Lakehead System) mainline between its origin at the United States/Canada border, near Neche, North Dakota, and Flanagan, Illinois. These projects include the expansion of Alberta Clipper (Line 67) and Southern Access (Line 61) and the construction of the Spearhead North Twin pipeline (Line 78). The expansion of Line 67 and construction of Line 78 were completed in 2015.


On October 16, 2017, the United States Department of State issued a Presidential Permit to EEP to operate Line 67 at its design capacity of 888,889 barrels per day at the border of the United States and Canada near Neche, North Dakota. The remaining scope of the Lakehead System Mainline Expansion includes the Southern Access expansion between Superior, Wisconsin and Flanagan, Illinois. The expansion to increase the pipeline capacity to 1,200,000 bpd at an expected cost of approximately US$0.4 billion was substantially completed in June of 2017. In conjunction with shippers, a decision was made to delay the in-service date of this phase of the Southern Access expansion to 2019 to align more closely with the anticipated in-service date for the United States portion of the Line 3 Replacement Program (U.S. L3R Program). EEP will operate this project on a cost-of-service basis. The Lakehead System Mainline Expansion is funded 75% by Enbridge and 25% by EEP under a joint funding agreement. Under that agreement, EEP has the option to increase its economic interest held by up to an additional 15% at cost. Line 3 Replacement Program The Line 3 Replacement Program (L3R Program) will support the safety and operational reliability of the mainline system, enhance system flexibility, allow the Company and EEP to optimize throughput on the mainline system and restore approximately 370,000 bpd of capacity from western Canada into Superior, Wisconsin. Canadian Line 3 Replacement Program (the Fund Group) The Canadian L3R Program will complement existing integrity programs by replacing approximately 1,084 kilometres (673 miles) of the remaining line segments of the existing Line 3 pipeline between Hardisty, Alberta and Gretna, Manitoba. In April 2016, the National Energy Board (NEB) found that the Canadian L3R Program is in the Canadian public interest and issued final conditions and a recommendation to the Federal Cabinet to approve the issuance of the Certificate of Public Convenience and Necessity (the Certificate) for the construction and operation of the pipeline and related facilities. Approval was received from the Government of Canada on November 29, 2016, with no material changes to permit conditions and on December 1, 2016, the NEB issued the Certificate. Once the Certificate was issued, Natural Resources Canada (NRCan) released the final assessment of the upstream greenhouse gas (GHG) emissions, as well as reports summarizing the additional Crown Consultation with Indigenous groups and the public online survey conducted by NRCan. In December 2016, the Manitoba Metis Federation (MMF) and the Association of Manitoba Chiefs (AMC) applied to the Federal Court of Appeal (FCA) for leave, which was subsequently granted, to judicially review the Government of Canada’s decision to approve the Canadian L3R Program. On July 4, 2017, the MMF discontinued its judicial review application. On October 25, 2017, the AMC discontinued its judicial review application. As a result, no further challenges to the Government of Canada's decision to approve the Canadian L3R Program may be brought by any party. On July 7, 2017, the NEB approved the Plan, Profile and Book of Reference for the Canadian L3R Program, meaning that the detailed route for the Canadian L3R Program has been approved. All required pre-construction filings have been approved by the NEB and construction commenced in early August 2017. Based on the updated execution plan, the revised cost of the project is $5.3 billion in Canada. This is roughly 8% above prior estimates and reflects the ongoing delays in the regulatory process, as well as some additional scope, route modifications and other changes as a result of the extensive consultation efforts and obligation to meet permit conditions. The impact of these additional costs are fully offset by lower estimated operating costs and a stronger United States dollar relative to the original project assumptions.


United States Line 3 Replacement Program (EEP) The U.S. L3R Program will complement existing integrity programs by replacing approximately 576 kilometres (358 miles) of the remaining line segments of the existing Line 3 pipeline between Neche, North Dakota and Superior, Wisconsin. EEP has the authorization to replace Line 3 in North Dakota and Wisconsin. EEP is in the process of obtaining the appropriate permits for constructing the U.S. L3R Program in Minnesota. The project requires both a Certificate of Need and an approval of the pipeline's route (Route Permit) from the MNPUC. The MNPUC found both the Certificate of Need and Route Permit applications for the U.S. L3R Program through Minnesota to be complete. On February 1, 2016, the MNPUC issued a written order requiring the Minnesota Department of Commerce (DOC) to prepare an Environmental Impact Statement (EIS) before the Certificate of Need and Route Permit processes commence. The DOC issued the final EIS on August 17, 2017. The MNPUC will determine its adequacy by December 2017. In the parallel Certificate of Need and Route Permit dockets, progress continues according to schedule with public hearings currently under way. The MNPUC is expected to issue a ruling in the second quarter of 2018. Construction commenced on the Wisconsin portion of U.S. L3R Program in late June 2017. Based on the updated execution plan, the revised cost of the project is US$2.9 billion in the United States. This is roughly 12% above prior estimates and reflects the ongoing delays in the regulatory process, as well as some additional scope, route modifications and other changes as a result of the extensive consultation efforts and obligation to meet permit conditions. EEP will recover the costs plus a return on capital based on its existing Facilities Surcharge Mechanism with the initial term of the agreement being 15 years. For the purpose of the toll surcharge, the agreement specifies a 30-year recovery of the capital based on a cost-of-service methodology. On January 26, 2017, Enbridge and EEP entered into an agreement for the joint funding of the U.S. L3R Program, whereby Enbridge and EEP will fund 99% and 1%, respectively, of the project cost. Enbridge has reimbursed EEP approximately US$450 million for expenditures incurred to date on the project and it will fund 99% of the capital costs through construction. EEP has the option to increase its economic interest by up to 40% at Enbridge’s cost until four years after the project is placed into service. Other - Canada: JACOS Hangingstone Project (the Fund Group) The Japan Canada Oil Sands Limited (JACOS) Hangingstone Project, a new pipeline connecting the JACOS Hangingstone project site to the Company's existing Cheecham Terminal, was placed into service on August 29, 2017. The 53-kilometre (33-mile), 12-inch diameter pipeline provides capacity of 40,000 bpd to the partners in the project, JACOS and Nexen Energy ULC, a wholly-owned subsidiary of China National Offshore Oil Corporation Limited. GAS PIPELINES AND PROCESSING Sabal Trail (SEP) The Sabal Trail project, a joint venture with NextEra Energy and Duke Energy, was placed into service in early July 2017. The project provides firm natural gas transportation to Florida Power & Light Company for its power generation needs and to Duke Energy Florida for its proposed natural gas plant in Florida. Facilities include a new 829 kilometre (515 mile) pipeline, laterals and various compressor stations. This new pipeline infrastructure is located in Alabama, Georgia and Florida, and adds approximately 1.1 billion cubic feet per day (bcf/d) of new capacity to access onshore shale gas supplies once approved future expansions are completed.


Access South, Adair Southwest and Lebanon Extension (SEP) SEP’s Access South, Adair Southwest and Lebanon Extension projects will provide shippers with the opportunity to deliver new natural gas supplies from the Appalachian region of the United States to markets in the Midwest and Southeast regions of the United States where demand for natural gas is high. The facilities for these projects include pipeline looping, as well as modifications and expansions of existing compressor stations on SEP’s Texas Eastern pipeline system. The combined projects are designed to deliver 622 million cubic feet per day (mmcf/d) of gas to customers in Ohio, Kentucky and Mississippi. These projects are expected to be placed into service by the end of 2017. Atlantic Bridge (SEP) The Atlantic Bridge project is an expansion designed to provide additional capacity of 133 mmcf/d to SEP’s Algonquin Gas Transmission and Maritimes & Northeast pipeline systems into New England and to specific end use markets in the Canadian Maritime provinces. The expansion primarily consists of the replacement of 10 kilometres (6 miles) of 26-inch pipeline with 42-inch pipeline, compression additions in Connecticut and a new compressor station in Massachusetts. The Connecticut portion of the project is expected to be placed into service in the fourth quarter of 2017. The Massachusetts portion of the project is expected to be placed into service in late 2018. NEXUS (SEP) Under a 50% joint venture with DTE Energy Company, the NEXUS project is a new pipeline system designed to transport up to 1.5 billion cubic feet per day (bcf/d) from SEP’s Texas Eastern pipeline system in Ohio to the Union Gas Dawn hub in Ontario. The facilities will consist of approximately 410 kilometres (255 miles) of 36-inch pipeline across northern Ohio to the Detroit, Michigan area, addition of four new compressor stations totalling 130,000 horsepower and six meter stations. The NEXUS project received Notice to Proceed from the Federal Energy Regulatory Commission (FERC) and construction activities have commenced. The expected in-service date is the third quarter of 2018. Based on an updated execution plan, the revised cost of the project is US$1.3 billion. This is roughly 18% above prior estimates and reflects the prolonged lack of FERC quorum and associated cost pressures. High Pine Westcoast Energy Inc.'s (Westcoast’s) High Pine project on the British Columbia Pipeline is a 240 mmcf/d expansion of the T-North pipeline system consisting of two 42-inch pipeline loops totalling approximately 37 kilometres (23 miles) in length in the Fort St. John region of British Columbia and an additional compressor unit with associated infrastructure at the Sunset Creek compressor site in northeastern British Columbia. The project, which had initially been expected to have its final phase in service by the end of 2017, has been delayed due to the impact of wildfires experienced in the third quarter of 2017 and the final phase is expected to be placed into service in the first quarter of 2018. Reliability and Maintainability Project Westcoast’s Reliability and Maintainability (RAM) project was designed to enhance the performance of the southern segment of the British Columbia Pipeline system to accommodate the increased base load on the system. The RAM project involves upgrading the southern segment of the British Columbia Pipeline system with three compressor station replacements. It will prepare the British Columbia Pipeline system to operate at a higher load factor as higher utilization rates are expected from new incremental year-round loads. The first two compressor stations are expected to be placed into service in the fourth quarter of 2017, with the final station expected to be placed into service in the first half of 2018.


Valley Crossing Pipeline The Valley Crossing Pipeline project will help Mexico meet its growing electric generation needs as generators shift away from fuel oil and imported LNG. The project will include a new 269 kilometre (167 mile) mainline pipeline that will consist of approximately 221 kilometres (138 miles) of 48-inch pipe and 48 kilometres (30 miles) of 42-inch pipe. The pipeline is designed to carry 2.6 bcf/d of gas from the Agua Dulce hub in Texas to an offshore tie-in with the Sur de Texas-Tuxpan project, which is being constructed by a third party. The Valley Crossing Pipeline is expected to be placed into service in the fourth quarter of 2018. Spruce Ridge Program Under the Spruce Ridge Program, Westcoast is pursuing an expansion of the British Columbia Pipeline in northern British Columbia, which consists of the Aitken Creek Looping project and the Spruce Ridge Expansion project. The Aitken Creek Looping project would consist of 13 kilometres (8 miles) of 24-inch pipe. The Spruce Ridge Expansion project would consist of 25 kilometres (16 miles) of 36-inch pipe, as well as the addition of new compressor units at two existing compressor stations. The expansion service agreements were executed in late 2016 and detailed engineering of the project is underway, with a targeted in-service date in 2019. T-South Expansion Program In the second quarter of 2017, Enbridge completed a successful binding open season on its British Columbia Pipeline T-South system for delivery of an incremental 190 mmcf/d of natural gas into the Huntington/Sumas market at the United States/Canada border. All customer contracts associated with the open season have been executed. The T-South system is currently fully contracted and an expansion is necessary to meet increasing customer demand as a result of rapidly growing production in the Montney region. The project will include looping along the T-South system and upgrades at compressor stations along the pipeline system and is expected to be in-service by late 2020. GAS DISTRIBUTION 2017 Dawn-Parkway Expansion The Union Gas 2017 Dawn-Parkway expansion project in Ontario involves a 419 mmcf/d expansion of the Dawn to Parkway transmission system consisting of the addition of a new 44,500 horsepower compressor at each of the Dawn, Lobo and Bright compressor stations in Ontario. The Dawn-Parkway expansion project was placed into service in October 2017. GREEN POWER AND TRANSMISSION Chapman Ranch Wind Project On September 9, 2016, Enbridge acquired a 100% interest in the 249-MW Chapman Ranch Wind Project, located in Nueces County, Texas, from Apex Clean Energy Holdings, LLC. The Chapman Ranch Wind Project consists of 81 Acciona Windpower North America, LLC (Acciona) turbines and was placed into service on October 25, 2017. The project was constructed under a fixed-price engineering, procurement and construction agreement, with Renewable Energy Systems America Inc. Acciona is providing turbine operations and maintenance services under a five-year fixed-price contract with an option to extend. The project is backed by a 12-year power offtake agreement. Hohe See Expansion Project In June 2017, the Company announced it had moved forward on its option to partner with German utility EnBW on an expansion of the previously announced Hohe See Offshore Wind Project (Hohe See Project). The Hohe See expansion project, to be located in the vicinity of the 497 megawatt Hohe See Project, will have a capacity of 112 megawatts. Similar to the Hohe See Project, the Hohe See expansion project will be constructed under fixed-price engineering, procurement, construction and installation contracts which have been secured with key suppliers. The Hohe See expansion project is backed by a government legislated 20-year revenue support mechanism and is expected to be placed into service alongside the Hohe See Project in 2019.


OTHER ANNOUNCED PROJECTS UNDER DEVELOPMENT The following projects have been announced by the Company, but have not yet met the Company’s criteria to be classified as commercially secured. The Company also has a large portfolio of additional projects under development that have not yet progressed to the point of public announcement. GAS PIPELINES AND PROCESSING Gulf Coast Express Pipeline Project In April 2017, DCP Midstream announced the signing of a letter of intent with Kinder Morgan Texas Pipeline LLC to participate in the development of the proposed Gulf Coast Express Pipeline Project. In October 2017, DCP Midstream also announced they have signed a letter of intent with an affiliate of Targa Resources Corp. with respect to the joint development of the project. The project will provide an outlet for increased natural gas production from the Permian Basin to growing markets along the Texas Gulf Coast. The project is designed to transport up to 1.7 bcf/d of natural gas through approximately 692 kilometres (430 miles) of 42-inch pipeline from the Waha, Texas area to Agua Dulce, Texas. The project is expected to be placed into service during the second half of 2019, subject to obtaining sufficient shipper commitments. GREEN POWER AND TRANSMISSION Éolien Maritime France SAS Enbridge has a 50% interest in Éolien Maritime France SAS (EMF), a French offshore wind development company. EMF is co-owned by Enbridge and EDF Energies Nouvelles, a subsidiary of Électricité de France S.A. EMF, through subsidiary companies, which holds licenses for three large-scale offshore wind farms off the coast of France. Combined, the three projects will have a capacity of 1,428 megawatts of power. The development of these projects is subject to a final investment decision and regulatory approvals, the timing of which is not yet certain. Enbridge’s portion of the costs incurred to date is approximately $244 million (€155 million).

LIQUIDITY AND CAPITAL RESOURCES The maintenance of financial strength and flexibility is fundamental to Enbridge’s growth strategy, particularly in light of the significant level of capital projects currently secured or under development. Access to timely funding from capital markets could be limited by factors outside Enbridge’s control, including but not limited to financial market volatility resulting from economic and political events both inside and outside North America. To mitigate such risks, the Company actively manages financial plans and funding strategies to ensure it maintains sufficient liquidity to meet routine operating and future capital requirements. In the near term, the Company generally expects to utilize cash from operations and capital markets issuances, commercial paper and/or credit facility draws to fund liabilities as they become due, finance capital expenditures, fund debt retirements and pay common and preference share dividends. The Company targets to maintain liquidity through securement of committed credit facilities with a diversified group of banks and financial institutions sufficient to enable it to fund all anticipated requirements for approximately one year without accessing the capital markets. The Company’s financing plan is regularly updated to reflect evolving capital requirements and financial market conditions and incorporates a variety of potential sources of debt and equity funding alternatives, including utilization of its sponsored vehicles, EEP, the Fund Group and SEP. CAPITAL MARKET ACCESS The Company and its self-funding subsidiaries ensure ready access to capital markets, subject to market conditions, through maintenance of shelf prospectuses that allow for issuance of long-term debt, equity and other forms of long-term capital when market conditions are attractive.


Bank Credit and Liquidity To ensure ongoing liquidity and to mitigate the risk of capital market disruption, Enbridge maintains ready access to funds through securement of committed bank credit facilities and it actively manages its bank funding sources to optimize pricing and ensure flexibility. The following table provides details of the Company’s committed credit facilities as at September 30, 2017.

September 30, 2017

Maturity

Dates Total

Facilities Draws1 Available


Enbridge2 2019-2022 7,349 5,089 2,260

Enbridge (U.S.) Inc. 2018-2019 3,665 786 2,879

EEP3 2019-2020 3,283 1,683 1,600

EGD 2019 1,016 766 250

Enbridge Income Fund 2020 1,500 611 889

Enbridge Pipelines (Southern Lights) L.L.C. 2019 25 — 25

Enbridge Pipelines Inc. 2019 3,000 1,499 1,501

Enbridge Southern Lights LP 2019 5 — 5

Spectra Energy Partners4,5 2022 3,127 2,544 583

Westcoast5 2021 400 156 244

Union Gas5 2021 700 670 30

Total committed credit facilities 24,070 13,804 10,266

1 Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility. 2 Includes $260 million of commitments that expire in 2018. 3 Includes $219 million (US$175 million) of commitments that expire in 2018. 4 Includes $237 million (US$190 million) of commitments that expire in 2021. 5 Committed credit facilities acquired as part of the merger with Spectra Energy. For additional information, refer to Merger with Spectra

Energy.

During the third quarter of 2017, the Company completed the following term debt offerings:

• US$1.4 billion of senior unsecured notes, which consist of two US$700 million tranches that mature in five and 10 years with fixed interest rates of 2.9% and 3.7%, respectively. Approximately US$1.4 billion of the net proceeds were used to complete a cash tender offer for and follow-up redemption of Spectra Energy Capital, LLC's (Spectra Capital) senior unsecured notes, as discussed below.

• US$1.0 billion of fixed-to-floating rate subordinated notes that mature in 60 years and are callable on or after year 10. For the initial 10 years, the notes carry a fixed interest rate of 5.5%. Subsequently, the interest rate will be set to equal the three-month London Interbank Offered Rate (LIBOR) plus a margin of 342 basis points from year 10 to 30, and a margin of 417 basis points from year 30 to 60.

• $1.0 billion of fixed-to-floating rate subordinated notes that mature in 60 years and are callable on or after year 10. For the initial 10 years, the notes carry a fixed interest rate of 5.4%. Subsequently, the interest rate will be set to equal the three-month Bankers' Acceptance Rate plus a margin of 325 basis points from year 10 to 30, and a margin of 400 basis points from year 30 to 60.

On July 7, 2017 and September 8, 2017, Enbridge and Spectra Capital completed a cash tender offer for and follow-up redemption of Spectra Capital’s outstanding 8.0% senior unsecured notes due 2019. The aggregate principal amount tendered and redeemed was US$500 million. Spectra Capital paid the consenting note holders an aggregate cash consideration of US$581 million. On July 13, 2017, pursuant to a cash tender offer, Spectra Capital purchased a portion of the principal amount of its outstanding senior unsecured notes carrying interest rates ranging from 3.3% to 7.5%, with maturities ranging from one to 21 years. The principal amount tendered and accepted was US$761


million. Spectra Capital paid the consenting note holders an aggregate cash consideration of US$857 million. The loss on debt extinguishment of $50 million (US$38 million), net of the fair value adjustment recorded upon completion of the Merger Transaction, was reported within Interest expense in the Consolidated Statements of Earnings. On October 10, 2017, Enbridge completed an offering of US$700 million of floating rate senior unsecured notes. These notes carry an interest rate equal to the three-month LIBOR plus 40 basis points, and mature on January 10, 2020. On October 13, 2017, Enbridge completed an offering of $650 million of fixed-to-floating rate subordinated notes that mature in 60 years and are callable on or after year 10. For the initial 10 years, the notes carry a fixed interest rate of 5.4%. Subsequently, the interest rate will be set to equal the three-month Bankers' Acceptance Rate plus a margin of 325 basis points from year 10 to 30, and a margin of 400 basis points from year 30 to 60. During the second quarter of 2017, the Company completed the following term debt offerings:

• $1.2 billion of unsecured medium-term notes with maturity dates ranging from 2022 to 2044 and fixed interest rates ranging from 3.2% to 4.6%.

• $750 million of unsecured floating rate notes that mature in 2019 and carry an interest rate equal to the three-month Bankers' Acceptance Rate plus 59 basis points.

• US$500 million of unsecured floating rate notes that mature in 2020 and carry an interest rate equal to the three-month LIBOR plus 70 basis points.

During the second quarter of 2017, SEP issued US$400 million of unsecured floating rate notes that mature in 2020 and carry an interest rate equal to the three-month LIBOR plus 70 basis points. During the first quarter of 2017, the Company established a five-year, term credit facility for $239 million (¥20,000 million) with a syndicate of Japanese banks. In addition to the committed credit facilities noted above, the Company also has $791 million (December 31, 2016 - $335 million) of uncommitted demand credit facilities, of which $412 million (December 31, 2016 - $177 million) were unutilized as at September 30, 2017. The Company’s net available liquidity of $11,011 million as at September 30, 2017, was inclusive of $745 million of unrestricted cash and cash equivalents as reported in the Consolidated Statements of Financial Position. The Company’s credit facility agreements and term debt indentures include standard events of default and covenant provisions whereby accelerated repayment and/or termination of the agreements may result if the Company were to default on payment or violate certain covenants. As at September 30, 2017, the Company was deemed to be in compliance with all debt covenants and expects to continue to comply with such covenants. Strong growth in internal cash flow, ready access to liquidity from diversified sources and a stable business model have enabled Enbridge to manage its credit profile. The Company actively monitors and manages key financial metrics with the objective of sustaining investment grade credit ratings from the major credit rating agencies and ongoing access to bank funding and term debt capital on attractive terms. Key measures of financial strength that are closely managed include the ability to service debt obligations from operating cash flow and the ratio of debt to total capital. As at September 30, 2017, the Company’s debt capitalization ratio was 48.9%, compared with 61.8% as at December 31, 2016. The improvement in the ratio reflected an increase in equity that resulted from the Merger Transaction.


Following the close of the Merger Transaction, the Company’s credit ratings were affirmed as follows:

• DBRS Limited confirmed the Company’s issuer rating and medium-term notes and unsecured debentures rating of BBB (high), fixed-to-floating subordinated notes rating of BBB (low), preference share rating of Pfd-3 (high) and commercial paper rating of R-2 (high), and changed their rating outlook from under review with developing implications to stable.

• Moody’s Investor Services, Inc. affirmed the Company’s issuer rating and senior unsecured debt rating of Baa2, subordinated rating of Ba1, preference share rating of Ba1 and commercial paper rating of P-2, and retained a negative outlook.

• Standard & Poor’s Rating Services (S&P) affirmed the Company’s corporate credit rating and senior unsecured debt rating of BBB+, preference share rating of P-2 (low) and commercial paper rating of A-1 (low), and reaffirmed a stable outlook. S&P also affirmed the Company’s global short-term rating of A-2.

• In June 2017, the Company obtained Fitch long-term issuer default rating and senior unsecured debt rating of BBB+, preference share rating of BBB-, junior subordinated note rating of BBB-, and short-term and commercial paper rating of F2 with a stable rating outlook.

Enbridge’s solid investment grade credit ratings are a reflection of the low risk nature of its underlying assets; limited exposure to commodity prices and volume risk; its project execution track record; strong dividend coverage; and substantial standby liquidity. The Company believes that it continues to have ample access to capital markets and standby liquidity in both Canada and the United States to fund the execution of its growth capital program. There are no material restrictions on the Company’s cash with the exception of the restricted cash of $102 million, which includes EGD’s and Union Gas’ receipt of cash from the Government of Ontario to fund its Green Investment Fund program. In addition, the Company’s restricted cash includes cash collateral and amounts for specific shipper commitments. Cash and cash equivalents held by EEP, the Fund Group and SEP are generally not readily accessible by Enbridge until distributions are declared and paid by these entities, which occurs quarterly for EEP and SEP, and monthly for the Fund Group. Further, cash and cash equivalents held by certain foreign subsidiaries may not be readily accessible for alternative uses by Enbridge. Excluding current maturities of long-term debt, the Company had a negative working capital position as at September 30, 2017. The major contributing factor to the negative working capital position was the ongoing funding of the Company’s growth capital program. To address this negative working capital position, the Company maintains significant liquidity in the form of committed credit facilities and other sources as previously discussed, which enable the funding of liabilities as they become due. As previously noted, as at September 30, 2017, the Company’s net available liquidity totalled $11,011 million (December 31, 2016 - $14,274 million). It is anticipated that any current maturities of long-term debt will be refinanced upon maturity. SOURCES AND USES OF CASH

Three months ended



Operating activities 1,533 922 5,243 4,153

Investing activities (2,172) (1,268 ) (8,063) (5,200 ) Financing activities 403 233 2,148 1,013

Effect of translation of foreign denominated cash and cash equivalents (45) 5

(77) (33 )

Decrease in cash and cash equivalents (281) (108 ) (749) (67 )


Significant sources and uses of cash for the three and nine months ended September 30, 2017 and September 30, 2016 are summarized below: Operating Activities

• The Company’s cash flows from operating activities increased by $611 million and $1,090 million for the three and nine months ended September 30, 2017, respectively, relative to the corresponding periods of 2016. The cash growth delivered by operations reflect operating factors discussed under Non-GAAP Measures – Adjusted EBIT.

• For the three and nine months ended September 30, 2017, partially offsetting the increase in cash flows from operating activities are transaction and transition costs in connection with the Merger Transaction, as well as employee severance costs in relation to the Company’s enterprise-wide reduction of workforce.

• Changes in operating assets and liabilities included within operating activities reflected a negative working capital of $409 million and $301 million for the three months ended September 30, 2017 and 2016, respectively. The Company reflected a positive working capital of $146 million and a negative working capital of $106 million for the nine months ended September 30, 2017 and 2016, respectively. Enbridge’s operating assets and liabilities fluctuate in the normal course due to various factors, including fluctuations in commodity prices and activity levels within the Energy Services and Gas Distribution segments, the timing of tax payments, as well as timing of cash receipts and payments. In addition, cap and trade regulation in the Province of Ontario went into effect on January 1, 2017, which resulted in recognition of a cap and trade compliance liability within the Gas Distribution segment in the first half of 2017.

Investing Activities

• Cash used in investing activities increased by $904 million and $2,863 million for the three and nine months ended September 30, 2017, respectively, relative to the corresponding periods of 2016. The increase was primarily attributable to increased investment in equity investments. During the first half of 2017, the Company paid cash consideration of $2.0 billion (US $1.5 billion) for the acquisition of an interest in the Bakken Pipeline System. In addition, the Company also made an equity investment of $0.5 billion in connection with its 50% interest in the Hohe See Project.

• This increase was also attributable to the Company’s continued execution of its growth capital program which is further described in Growth Projects – Commercially Secured Projects. The timing of project approval, construction and in-service dates impacts the timing of cash requirements.

• Also, during 2017, the Company’s investment in intangible assets in relation to the cap and trade regulation was higher compared with the corresponding 2016 period.

• The above increase in cash usage was partially offset by cash acquired in the Merger Transaction in the first quarter of 2017, proceeds from the disposition of the Ozark Pipeline, Sandpiper assets and Olympic Pipeline in 2017 and a cash reimbursement of capital expenditure from a natural gas producer relating to a suspended pipeline project in the second quarter of 2017.

Financing Activities

• Net cash generated from financing activities increased by $170 million and $1,135 million for the three and nine months ended September 30, 2017, respectively, relative to the corresponding periods of 2016. During the three and nine months ended 2017, the Company issued a series of medium term fixed and floating rate notes, the proceeds of which were used to repay maturing term notes and credit facilities and to finance growth capital programs. For the three months ended 2017, proceeds from term note issuances were primarily used to repay credit facilities and redeem tender offers for Spectra Capital’s outstanding senior unsecured notes as discussed in Liquidity and Capital Resources - Capital Market Access - Bank Credit and Liquidity.


• The change in cash generated from financing activities for the three and nine months ended 2017, reflected overall higher cash contributions from noncontrolling interests, which now include noncontrolling interests in the assets acquired through the Merger Transaction, which is more than offset by the increase in distributions to noncontrolling interests. For the three and nine months ended, the increase in distributions to noncontrolling interests were primarily attributable to the acquired assets, which were partially offset by the decrease in distributions resulting from the EEP strategic restructuring discussed under United States Sponsored Vehicle Strategy.

• For the nine months ended 2017, the above increases in cash were partially offset by the $227 million paid to acquire all of the outstanding publicly-held common units of MEP during the second quarter of 2017, as well as higher cash received from the issuance of common shares in the first quarter of 2016, as a result of the issuance of 56 million common shares in March 2016.

• Finally, the Company’s common share dividend payments increased in the first half of 2017, primarily due to the increase in the common share dividend rate effective March 2017, as well as higher number of common shares outstanding as a result of the issuance of approximately 75 million common shares in 2016 and 691 million common shares issued in connection with the Merger Transaction.

Dividend Reinvestment and Share Purchase Plan Participants in the Company’s Dividend Reinvestment and Share Purchase Plan receive a 2% discount on the purchase of common shares with reinvested dividends. For the three months ended September 30, 2017, dividends declared were $1,001 million (2016 - $496 million), of which $650 million (2016 - $300 million) were paid in cash and reflected in financing activities. The remaining $351 million (2016 - $196 million) of dividends declared were reinvested pursuant to the plan and resulted in the issuance of common shares rather than a cash payment. For the nine months ended September 30, 2017, dividends declared were $2,552 million (2016 - $1,448 million), of which $1,663 million (2016 - $857 million) were paid in cash and reflected in financing activities. The remaining $889 million (2016 - $591 million) of dividends declared were reinvested pursuant to the plan and resulted in the issuance of common shares rather than a cash payment. For the three and nine months ended September 30, 2017, 35.1% (2016 - 39.5%) and 34.8% (2016 - 40.8%), respectively, of total dividends declared were reinvested.


On November 1, 2017, the Enbridge Board of Directors declared the following quarterly dividends. All dividends are payable on December 1, 2017, to shareholders of record on November 15, 2017.

Common Shares $0.61000 Preference Shares, Series A $0.34375

Preference Shares, Series B1 $0.21340

Preference Shares, Series C2 $0.19571

Preference Shares, Series D $0.25000

Preference Shares, Series F $0.25000

Preference Shares, Series H $0.25000

Preference Shares, Series J3 US$0.30540 Preference Shares, Series L4 US$0.30993 Preference Shares, Series N $0.25000

Preference Shares, Series P $0.25000

Preference Shares, Series R $0.25000

Preference Shares, Series 1 US$0.25000 Preference Shares, Series 3 $0.25000

Preference Shares, Series 5 US$0.27500 Preference Shares, Series 7 $0.27500

Preference Shares, Series 9 $0.27500



Preference Shares, Series 15 $0.27500 Preference Shares, Series 17 $0.32188

1 The quarterly dividend amount of Series B was reset to $0.21340 from $0.25000 on June 1, 2017, due to reset on every fifth anniversary thereafter.

2 The quarterly dividend amount of Series C was set at $0.18600 on June 1, 2017 and $0.19571 on September 1, 2017, due to reset on a quarterly basis thereafter.

3 The quarterly dividend amount of Series J was reset to US$0.30540 from US$0.25000 on June 1, 2017, due to reset on every fifth anniversary thereafter.

4 The quarterly dividend amount of Series L was reset to US$0.30993 from US$0.25000 on September 1, 2017, due to reset on every fifth anniversary thereafter.

LEGAL AND OTHER UPDATES REPORTING REQUIREMENTS Effective January 1, 2018, Enbridge intends to comply with Securities and Exchange Commission reporting requirements applicable to United States domestic issuers and, accordingly, will file its annual report on Form 10-K for the year ended December 31, 2017 and regular periodic reports under both Canadian and U.S. law thereafter. LIQUIDS PIPELINES Renewal of Line 5 Easement On January 4, 2017, the Tribal Council of the Bad River Band of Lake Superior Tribe of Chippewa Indians (the Band) issued a press release indicating that the Band had passed a resolution not to renew its interest in certain Line 5 easements through the Bad River Reservation. Line 5 is included within the Company’s mainline system. The Band’s resolution calls for decommissioning and removal of the pipeline from all Bad River tribal lands and watershed and could impact the Company’s ability to operate the pipeline on the Reservation. Since the Band passed the resolution, the parties have agreed to ongoing discussions with the objective of understanding and resolving the Band’s concerns on a long-term basis.


Eddystone Rail Legal Matter In February 2017, Enbridge subsidiary Eddystone Rail filed an action against several defendants in the United States District Court for the Eastern District of Pennsylvania. Eddystone Rail alleges that the defendants transferred valuable assets from Eddystone Rail’s counterparty in a maritime contract, so as to avoid outstanding obligations to Eddystone Rail. Eddystone Rail is seeking payment of compensatory and punitive damages in excess of US$140 million. Eddystone Rail’s chances of success in connection with the above noted action cannot be predicted and it is possible that Eddystone Rail may not recover any of the amounts sought. On July 19, 2017, the defendants’ motions to dismiss Eddystone Rail’s claims were denied. Defendants have filed Answers and Counterclaims, which together with subsequent amendments, seek damages from Eddystone Rail in excess of US$32 million. Eddystone filed a motion to dismiss the counterclaims and defendants amended their Answer and Counterclaims on September 21, 2017. On October 12, 2017 Eddystone Rail moved to dismiss the latest version of defendants’ counterclaims. The defendants’ chances of success on their counterclaims cannot be predicted at this time. Results of operations from Eddystone Rail are reported within Liquids Pipelines – Feeder Pipelines and Other. Dakota Access Pipeline As noted previously under United States Sponsored Vehicle Strategy – Finalization of Bakken Pipeline System Joint Funding Agreement, the Company’s investment in the Bakken Pipeline System is inclusive of the Dakota Access Pipeline. In February 2017, the Standing Rock Sioux Tribe and the Cheyenne River Sioux Tribe filed motions with the US District Court for the District of Columbia (Court) contesting the validity of the process used by the United States Army Corps of Engineers (Army Corps) to permit the Dakota Access Pipeline. The plaintiffs requested the Court to order the operator to shut down the pipeline until the appropriate regulatory process is completed. On June 14, 2017, the Court ruled that the Army Corps failed to adequately consider the impact of an oil spill on the hunting and fishing rights of the Tribes and ordered the Army Corps to reconsider those components of its environmental analysis. The Court did not rule on whether the Dakota Access Pipeline should cease operations, but on June 21, 2017, the Court established a briefing schedule pursuant to which the parties to the litigation were provided with an opportunity to submit written arguments on this issue. Final briefs were filed by the parties in late August 2017. On October 11, 2017, the Court issued an order that allows the Dakota Access Pipeline to continue operating while the Army Corps completes the additional environmental review required by the Court's June 14, 2017 order. Lakehead System Lines 6A and Line 6B Crude Oil Release Line 6B Crude Oil Release On July 26, 2010, a release of crude oil on Line 6B of EEP’s Lakehead System was reported near Marshall, Michigan. As at September 30, 2017, EEP’s cumulative cost estimate for the Line 6B crude oil release remains at US$1.2 billion ($195 million after-tax attributable to Enbridge) including those costs that were considered probable and that could be reasonably estimated at September 30, 2017. As at September 30, 2017, EEP's remaining estimated liability is approximately US$64 million. Insurance Recoveries EEP is included in the comprehensive insurance program that is maintained by Enbridge for its subsidiaries and affiliates. As at September 30, 2017, EEP has recorded total insurance recoveries of US$547 million ($80 million after-tax attributable to Enbridge) for the Line 6B crude oil release out of the US$650 million applicable limit. Of the remaining US$103 million coverage limit, US$85 million was the subject matter of a lawsuit against one particular insurer. In March 2015, Enbridge reached an agreement with that insurer to submit the US$85 million claim to binding arbitration. On May 2, 2017, the arbitration panel issued a decision that was not favourable to Enbridge. As a result, EEP will not receive any additional insurance recoveries in connection with the Line 6B crude oil release.


Legal and Regulatory Proceedings A number of United States governmental agencies and regulators initiated investigations into the Line 6B crude oil release. As at September 30, 2017, there are no claims pending against Enbridge, EEP or their affiliates in United States state courts in connection with the Line 6B crude oil release. Enbridge has accrued a provision for future legal costs and probable losses associated with the Line 6B crude oil release as described above in this footnote. Line 6B Fines and Penalties As at September 30, 2017, EEP’s total estimated costs related to the Line 6B crude oil release include US$68 million in paid fines and penalties, which includes fines and penalties paid to the United States Department of Justice (DOJ) as discussed below. Consent Decree On May 23, 2017, the United States District Court for the Western District of Michigan, Southern Division, approved the Consent Decree. The Consent Decree is EEP’s signed settlement agreement with the United States Environmental Protection Agency and the DOJ regarding the Lines 6A and 6B crude oil releases. On June 15, 2017, Enbridge made a total payment of US$68 million as required by the Consent Decree, which reflects US$61 million for the civil penalty for the Line 6B release, US$1 million for the Line 6A release, and US$6 million for past removal costs and interest. Seaway Pipeline Regulatory Matters Seaway Crude Pipeline System (Seaway Pipeline) filed an application for market-based rates in December 2011 and refiled in December 2014. Several parties filed comments in opposition alleging that the application should be denied because Seaway Pipeline has market power in both its receipt and destination markets. On December 1, 2016, the Administrative Law Judge (ALJ) issued its decision which concluded that the Commission should grant the application of Seaway Pipeline for authority to charge market-based rates. The parties filed briefs during the first quarter of 2017 to defend the ALJ’s decision and to respond to criticisms of that decision. The Commissioners will now review the entire record and issue a decision. There is no timeline for the FERC to act and issue a decision. GAS PIPELINES AND PROCESSING Aux Sable Environmental Protection Agency Matter On October 14, 2016, an amended claim was filed against Aux Sable by a counterparty to an NGL supply agreement. On January 5, 2017, Aux Sable filed a Statement of Defence with respect to this claim. While the final outcome of this action cannot be predicted with certainty, at this time management believes that the ultimate resolution of this action will not have a material impact on the Company’s consolidated financial position or results of operations. CAPITAL EXPENDITURE COMMITMENTS The Company has signed contracts for the purchase of services, pipe and other materials totalling $4,996 million which are expected to be paid over the next five years. TAX MATTERS Enbridge and its subsidiaries maintain tax liabilities related to uncertain tax positions. While fully supportable in the Company’s view, these tax positions, if challenged by tax authorities, may not be fully sustained on review.


OTHER LITIGATION The Company and its subsidiaries are subject to various other legal and regulatory actions and proceedings which arise in the normal course of business, including interventions in regulatory proceedings and challenges to regulatory approvals and permits by special interest groups. While the final outcome of such actions and proceedings cannot be predicted with certainty, management believes that the resolution of such actions and proceedings will not have a material impact on the Company’s consolidated financial position or results of operations.

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS The Company’s earnings, cash flows and other comprehensive income (OCI) are subject to movements in foreign exchange rates, interest rates, commodity prices and the Company’s share price. The following summarizes the types of market risks to which the Company is exposed and the risk management instruments used to mitigate them. The Company uses a combination of qualifying and non-qualifying derivative instruments to manage the risks noted below. Foreign Exchange Risk The Company generates certain revenues, incurs certain expenses and holds a number of investments and subsidiaries that are denominated in currencies other than Canadian dollars. As a result, the Company’s earnings, cash flows and OCI are exposed to fluctuations resulting from foreign exchange rate variability. The Company has implemented a policy whereby, at a minimum, it hedges a level of foreign currency denominated earnings exposures over a five-year forecast horizon. A combination of qualifying and non-qualifying derivative instruments are used to hedge anticipated foreign currency denominated revenues and expenses, and to manage variability in cash flows. The Company hedges certain net investments in United States dollar denominated investments and subsidiaries using foreign currency derivatives and United States dollar denominated debt. Interest Rate Risk The Company’s earnings and cash flows are exposed to short-term interest rate variability due to the regular repricing of its variable rate debt, primarily commercial paper. Pay fixed-receive floating interest rate swaps and options are used to hedge against the effect of future interest rate movements. The Company has implemented a program to significantly mitigate the impact of short-term interest rate volatility on interest expense via execution of floating to fixed interest rate swaps with an average swap rate of 2.5%. As a result of the Merger Transaction, the Company is exposed to changes in the fair value of the fixed rate debt that arise as a result of the changes in market interest rates. Pay floating-receive fixed interest rate swaps are used to hedge against the future changes to the fair value of the fixed rate debt. The Company has implemented a program to significantly mitigate the impact of fluctuations in the fair value of the fixed rate debt via execution of fixed to floating interest rate swaps with an average swap rate of 2.2%. The Company’s earnings and cash flows are also exposed to variability in longer term interest rates ahead of anticipated fixed rate term debt issuances. Forward starting interest rate swaps are used to hedge against the effect of future interest rate movements. The Company has implemented a program to significantly mitigate its exposure to long-term interest rate variability on select forecast term debt issuances via execution of floating to fixed interest rate swaps with an average swap rate of 3.6%.


The Company also monitors its debt portfolio mix of fixed and variable rate debt instruments to maintain a consolidated portfolio of debt within its Board of Directors approved policy limit of a maximum of 25% floating rate debt as a percentage of total debt outstanding. The Company primarily uses qualifying derivative instruments to manage interest rate risk. Commodity Price Risk The Company’s earnings and cash flows are exposed to changes in commodity prices as a result of its ownership interests in certain assets and investments, as well as through the activities of its Energy Services subsidiaries. These commodities include natural gas, crude oil, power and NGL. The Company employs financial derivative instruments to fix a portion of the variable price exposures that arise from physical transactions involving these commodities. The Company uses primarily non-qualifying derivative instruments to manage commodity price risk. Emission Allowance Price Risk Emission allowance price risk is the risk of gain or loss due to changes in the market price of emission allowances that the gas distribution business of the Company is required to purchase for itself and most of its customers to meet GHG compliance obligations. Similar to the gas supply procurement framework, the OEB framework for emission allowance procurement allows recovery of fluctuations in emission allowance prices in customer rates, subject to OEB approval. Equity Price Risk Equity price risk is the risk of earnings fluctuations due to changes in the Company’s share price. The Company has exposure to its own common share price through the issuance of various forms of stock-based compensation, which affect earnings through revaluation of the outstanding units every period. The Company uses equity derivatives to manage the earnings volatility derived from one form of stock-based compensation, restricted share units. The Company uses a combination of qualifying and non-qualifying derivative instruments to manage equity price risk.


THE EFFECT OF DERIVATIVE INSTRUMENTS ON THE STATEMENTS OF EARNINGS AND COMPREHENSIVE INCOME The following table presents the effect of cash flow hedges and net investment hedges on the Company’s consolidated earnings and consolidated comprehensive income, before the effect of income taxes.

Three months ended



Amount of unrealized gain/(loss) recognized in OCI Cash flow hedges

Foreign exchange contracts (2) 2 (1) (31 ) Interest rate contracts 83 108 28 (896 ) Commodity contracts — 12 12 10

Other contracts 16 9 1 46

Net investment hedges Foreign exchange contracts 148 (14 ) 221 58

245 117 261 (813 ) Amount of (gain)/loss reclassified from Accumulated

other comprehensive income (AOCI) to earnings (effective portion)

Foreign exchange contracts1 (3) — (104) 2

Interest rate contracts2 50 51 134 102

Commodity contracts3 — (2 ) (4) (8 ) Other contracts4 (11) (5 ) 2 (35 )

36 44 28 61

Amount of (gain)/loss reclassified from AOCI to earnings (ineffective portion and amount excluded from effectiveness testing)

Interest rate contracts2 (1) 17 5 48

(1) 17 5 48

Amount of gain/(loss) from non-qualifying derivatives included in earnings

Foreign exchange contracts1 503 49 1,210 1,093


Commodity contracts3 (160) (47 ) 22 (345 ) Other contracts4 3 5 (2) 16

345 67 1,243 832

1 Reported within Transportation and other services revenues and Other income/(expense) in the Consolidated Statements of Earnings.

2 Reported within Interest expense in the Consolidated Statements of Earnings. 3 Reported within Transportation and other services revenues, Commodity sales revenues, Commodity costs and Operating and

administrative expense in the Consolidated Statements of Earnings. 4 Reported within Operating and administrative expense in the Consolidated Statements of Earnings.


Fair Value Derivatives For interest rate derivative instruments that are designated and qualify as fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged risk is included in Interest expense in the Consolidated Statements of Earnings. During the three and nine months ended September 30, 2017, the Company recognized an unrealized loss of nil and $1 million, respectively (2016 - nil) on the derivative and an unrealized gain of $1 million and $2 million, respectively (2016 - nil) on the hedged item in earnings. During the three and nine months ended September 30, 2017, the Company recognized a realized gain of $2 million and $2 million (2016 - nil) on the derivative and a realized loss of $2 million and $2 million (2016 - nil) on the hedged item in earnings. The difference in the amounts, if any, represents hedge ineffectiveness. LIQUIDITY RISK Liquidity risk is the risk that the Company will not be able to meet its financial obligations, including commitments and guarantees, as they become due. In order to mitigate this risk, the Company forecasts cash requirements over a 12 month rolling time period to determine whether sufficient funds will be available and maintains substantial capacity under its committed bank lines of credit to address any contingencies. The Company’s primary sources of liquidity and capital resources are funds generated from operations, the issuance of commercial paper and draws under committed credit facilities and long-term debt, which includes debentures and medium-term notes. The Company also maintains current shelf prospectuses with securities regulators, which enables, subject to market conditions, ready access to either the Canadian or United States public capital markets. In addition, the Company maintains sufficient liquidity through committed credit facilities with a diversified group of banks and institutions which, if necessary, enables the Company to fund all anticipated requirements for approximately one year without accessing the capital markets. The Company is deemed to be in compliance with all the terms and conditions of its committed credit facilities as at September 30, 2017. As a result, all credit facilities are available to the Company and the banks are obligated to fund and have been funding the Company under the terms of the facilities. CREDIT RISK Entering into derivative financial instruments may result in exposure to credit risk from the possibility that a counterparty will default on its contractual obligations. In order to mitigate this risk, the Company enters into risk management transactions primarily with institutions that possess investment grade credit ratings. Credit risk relating to derivative counterparties is mitigated by credit exposure limits and contractual requirements, netting arrangements, and ongoing monitoring of counterparty credit exposure using external credit rating services and other analytical tools. The Company generally has a policy of entering into individual International Swaps and Derivatives Association, Inc. agreements or other similar derivative agreements with the majority of its derivative counterparties. These agreements provide for the net settlement of derivative instruments outstanding with specific counterparties in the event of bankruptcy or other significant credit event, and would reduce the Company’s credit risk exposure on derivative asset positions outstanding with the counterparties in these particular circumstances. Credit risk also arises from trade and other long-term receivables and is mitigated through credit exposure limits and contractual requirements, assessment of credit ratings and netting arrangements. Within EGD and Union Gas, credit risk is mitigated by the utilities’ large and diversified customer base and the ability to recover an estimate for doubtful accounts through the ratemaking process. The Company actively monitors the financial strength of large industrial customers and, in select cases, has obtained additional security to minimize the risk of default on receivables. Generally, the Company classifies and provides for receivables older than 30 days as past due. The maximum exposure to credit risk related to non-derivative financial assets is their carrying value.


CHANGES IN ACCOUNTING POLICIES ADOPTION OF NEW STANDARDS Simplifying the Measurement of Goodwill Impairment Effective January 1, 2017, the Company early adopted Accounting Standards Update (ASU) 2017-04 and applied the standard on a prospective basis. Under the new guidance, goodwill impairment will now be measured by the amount by which a reporting unit’s carrying value exceeds its fair value; this amount should not exceed the carrying amount of goodwill. The adoption of the pronouncement did not have a material impact on the Company’s consolidated financial statements. Clarifying the Definition of a Business in an Acquisition Effective January 1, 2017, the Company early adopted ASU 2017-01 on a prospective basis. The new standard was issued with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (disposals) of assets or businesses. The adoption of the pronouncement did not have a material impact on the Company’s consolidated financial statements. Accounting for Intra-Entity Asset Transfers Effective January 1, 2017, the Company early adopted ASU 2016-16 on a modified retrospective basis. The new standard was issued with the intent of improving the accounting for the income tax consequences of intra-entity asset transfers other than inventory. Under the new guidance, an entity should recognize the income tax consequences of an intra-entity transfer of an asset, other than inventory, when the transfer occurs. The adoption of the pronouncement did not have a material impact on the Company’s consolidated financial statements. Improvements to Employee Share-Based Payment Accounting Effective January 1, 2017, the Company adopted ASU 2016-09 and applied certain amendments on a modified retrospective basis with the remaining amendments applied on a prospective basis. The new standard was issued with the intent of simplifying and improving several aspects of accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The adoption of the pronouncement did not have a material impact on the Company’s consolidated financial statements. Simplifying the Embedded Derivatives Analysis for Debt Instruments Effective January 1, 2017, the Company adopted ASU 2016-06 on a modified retrospective basis. The new guidance simplifies the embedded derivative analysis for debt instruments containing contingent call or put options. The adoption of the pronouncement did not have a material impact on the Company’s consolidated financial statements. FUTURE ACCOUNTING POLICY CHANGES Improvements to Accounting for Hedging Activities ASU 2017-12 was issued in August 2017 with the main objective of better aligning a company’s risk management activities and the resulting hedge accounting reflected in the financial statements. The amendments allow cash flow hedging of contractually specified components in financial and non-financial items and make fair value hedges of interest rate risks more effective in certain circumstances. Under the new guidance, hedge ineffectiveness is no longer required to be measured and hedging instruments’ fair value changes will be recorded in the same income statement line as the hedged item. The ASU also allows the initial quantitative hedge effectiveness assessment to be performed at any time before the end of the quarter in which the hedge is designated. After initial quantitative testing is performed, an ongoing qualitative effectiveness assessment is permitted. The Company is currently assessing the impact of the new standard on the consolidated financial statements. The accounting update is effective for annual and interim periods beginning after December 15, 2018, with early adoption permitted, and is to be applied on a modified retrospective basis.


Clarifying Guidance on the Application of Modification Accounting on Stock Compensation ASU 2017-09 was issued in May 2017 with the intent to clarify the scope of modification accounting and when it should be applied to a change to the terms or conditions of a share based payment award. Under the new guidance, modification accounting is required for all changes to share based payment awards, unless all of the following are met: 1) there is no change to the fair value of the award, 2) the vesting conditions have not changed, and 3) the classification of the award as an equity instrument or a debt instrument has not changed. The accounting update is effective for annual periods beginning after December 15, 2017 and is to be applied on a prospective basis. The adoption of ASU 2017-09 is not expected to have a material impact on the Company’s consolidated financial statements. Amending the Amortization Period for Certain Callable Debt Securities Purchased at a Premium ASU 2017-08 was issued in March 2017 with the intent of shortening the amortization period to the earliest call date for certain callable debt securities held at a premium. The Company is currently assessing the impact of the new standard on the consolidated financial statements. The accounting update is effective for annual and interim periods beginning after December 15, 2018 and is to be applied on a modified retrospective basis. Improving the Presentation of Net Periodic Benefit Cost Related to Defined Benefit Plans ASU 2017-07 was issued in March 2017 primarily to improve the income statement presentation of the components of net periodic pension cost and net periodic postretirement benefit cost for an entity’s sponsored defined benefit pension and other postretirement plans. In addition, only the service-cost component of net benefit cost is eligible for capitalization. The accounting update is effective for annual and interim periods beginning after December 15, 2017 and is to be applied on a retrospective basis for the statement of earnings presentation component and a prospective basis for the capitalization component. The Company is currently assessing the impact of the new standard on the consolidated financial statements. Clarifying Guidance on Derecognition and Partial Sales of Nonfinancial Assets ASU 2017-05 was issued in February 2017 with the intent of clarifying the scope of asset derecognition guidance and accounting for partial sales of nonfinancial assets. The ASU clarifies the scope provisions of nonfinancial assets and how to allocate consideration to each distinct asset, and amends the guidance for derecognition of a distinct nonfinancial asset in partial sale transactions. The Company is currently assessing the impact of the new standard on the consolidated financial statements. The accounting update is effective for annual and interim periods beginning after December 15, 2017 and is to be applied on a retrospective or modified retrospective basis. Accounting for Credit Losses ASU 2016-13 was issued in June 2016 with the intent of providing financial statement users with more useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. Current treatment uses the incurred loss methodology for recognizing credit losses that delays the recognition until it is probable a loss has been incurred. The amendment adds a new impairment model, known as the current expected credit loss model, which is based on expected losses rather than incurred losses. Under the new guidance, an entity recognizes as an allowance its estimate of expected credit losses, which the Financial Accounting Standards Board believes will result in more timely recognition of such losses. The Company is currently assessing the impact of the new standard on its consolidated financial statements. The accounting update is effective for annual and interim periods beginning on or after December 15, 2019. Recognition of Leases ASU 2016-02 was issued in February 2016 with the intent to increase transparency and comparability among organizations. It requires lessees of operating lease arrangements to recognize lease assets and lease liabilities on the statement of financial position and disclose additional key information about lease agreements. The accounting update also replaces the current definition of a lease and requires that an arrangement be recognized as a lease when a customer has the right to obtain substantially all of the


economic benefits from the use of an asset, as well as the right to direct the use of the asset. The Company is currently gathering a complete inventory of its lease contracts in order to assess the impact of the new standard on its consolidated financial statements. The accounting update is effective for fiscal years beginning after December 15, 2018 and is to be applied using a modified retrospective approach. Revenue from Contracts with Customers ASU 2014-09 was issued in 2014 with the intent of significantly enhancing consistency and comparability of revenue recognition practices across entities and industries. The new standard establishes a single, principles-based five-step model to be applied to all contracts with customers and introduces new and enhanced disclosure requirements. The standard is effective for fiscal years beginning after December 15, 2017. The new revenue standard permits either a full retrospective method of adoption with restatement of all prior periods presented, or a modified retrospective method with the cumulative effect of applying the new standard recognized as an adjustment to opening retained earnings in the period of adoption. The Company has decided to adopt the new revenue standard using the modified retrospective method. The Company has reviewed a sample of its revenue contracts in order to evaluate the effect of the new standard on its revenue recognition practices. Based on the Company’s initial assessment, the application of the standard may result in a change in presentation in the Gas Distribution business related to payments to customers under the earnings sharing mechanism which are currently shown as an expense in the Consolidated Statements of Earnings. Under the new standard, these payments would be reflected as a reduction of revenue. Additionally, estimates of variable consideration which will be required under the new standard as well as the allocation of the transaction price for certain revenue contracts, may result in changes to the pattern or timing of revenue recognition for those contracts. While the Company has not yet completed the assessment, the Company’s preliminary view is that it does not expect these changes will have a material impact on revenue or earnings/(loss). The Company has also developed and tested processes to generate the disclosures required under the new standard.


QUARTERLY FINANCIAL INFORMATION

2017 2016 2015 Q32 Q22 Q12 Q4 Q3 Q2 Q1 Q4 (millions of Canadian dollars, except per share amounts) Revenues 9,227 11,116 11,146 9,338 8,488 7,939 8,795 8,914

Earnings/(loss) attributable to common shareholders 765

919

638

365

(103) 301

1,213

378

Earnings/(loss) per common share 0.47

0.56

0.54

0.39

(0.11) 0.33

1.38

0.44

Diluted earnings/(loss) per common share 0.47

0.56

0.54

0.39

(0.11) 0.33

1.38

0.44

Dividends per common share 0.610 0.610 0.583 0.530 0.530 0.530 0.530 0.465

Changes in unrealized derivative fair value (gains)/loss1 (748 ) (537) (245) 189

32

1

(652) 45

1 Included in earnings/(loss) attributable to common shareholders. 2 Included in the first and second quarters of 2017 were the results of operations from the assets acquired through the Merger

Transaction. For additional information, refer to Merger with Spectra Energy, Liquids Pipelines, Gas Pipelines and Processing, Gas Distribution, as well as Eliminations and Other.

Several factors impact comparability of the Company’s financial results on a quarterly basis, including, but not limited to, the Merger Transaction in the first quarter of 2017, seasonality in the Company’s gas distribution businesses, fluctuations in market prices such as foreign exchange rates and commodity prices, disposals of investments or assets and the timing of in-service dates of new projects. A significant part of the Company’s revenues is generated from its energy services operations. Revenues from these operations depend on activity levels, which vary from year to year depending on market conditions and commodity prices. Commodity prices do not directly impact earnings since these earnings reflect a margin or percentage of revenues that depends more on differences in commodity prices between locations and points in time than on the absolute level of prices. The Company actively manages its exposure to market risks including, but not limited to, commodity prices, interest rates and foreign exchange rates. To the extent derivative instruments used to manage these risks are non-qualifying for the purposes of applying hedge accounting, changes in unrealized fair value gains and losses on these instruments will impact earnings. In addition to the impacts of the Merger Transaction, as well as the changes in unrealized gains and losses outlined above, significant items impacting the consolidated quarterly earnings are noted below:

• Included in the first quarter of 2017 were charges to earnings of $152 million ($111 million after-tax) with respect to costs incurred in relation to the Merger Transaction, as well as $129 million ($92 million after-tax) of employee severance costs in relation to the Company’s enterprise-wide reduction of workforce in March 2017 and restructuring costs in connection with the completion of the Merger Transaction.

• Included in the fourth quarter of 2016 were employee severance and restructuring costs incurred in relation to the Company’s Building Our Energy Future initiative, with a net charge to earnings of $37 million. For additional information on this initiative, refer to the Company’s 2016 annual MD&A.

• Included in the fourth quarter of 2016 was a gain of $520 million (after-tax attributable to Enbridge) on the disposal of South Prairie Region assets within the Liquids Pipelines segment.

• Included in the fourth quarter of 2016 was an asset impairment charge of $272 million (after-tax attributable to Enbridge) related to the Northern Gateway Project within the Liquids Pipelines segment.


• Included in the fourth quarter of 2016 and second quarter of 2015 were the tax impacts of asset transfers between entities under common control of Enbridge. The intercompany gains realized by the selling entities have been eliminated from the Company’s consolidated financial statements. However, as the transaction involved the sale of partnership units, the tax consequences remained in consolidated earnings and resulted in charges of $11 million and $39 million, respectively.

• In the third quarter of 2016, impairment charges of $1,000 million ($81 million after-tax attributable to Enbridge), including related project costs of $8 million, were recognized in relation to EEP’s Sandpiper Project. In the fourth quarter of 2016, additional project costs of $4 million (nil after-tax attributable to Enbridge) were recognized.

• Included in the second and third quarters of 2016 were after-tax costs attributable to Enbridge of $12 million and $10 million, respectively, incurred in relation to the restart of certain of Enbridge’s pipelines and facilities following the northeastern Alberta wildfires.

• Included in the second quarter of 2016 were impairment charges of $103 million (after-tax attributable to Enbridge) related to Enbridge’s 75% joint venture interest in Eddystone Rail, attributable to market conditions that impacted volumes at the rail facility.

• Included in the fourth quarter of 2015 were employee severance costs in relation to the Company’s enterprise-wide reduction of workforce, with a net charge of $25 million to earnings.

• Included in the fourth quarter of 2015 was an asset impairment charge of US$63 million ($11 million after-tax attributable to Enbridge) related to EEP’s Berthold rail facility due to the inability to renew committed shipper agreements beyond 2016 or secure sufficient spot volume.

Finally, the Company is in the midst of a substantial growth capital program and the timing of construction and completion of growth projects may impact the comparability of quarterly results. The Company’s capital expansion initiatives, including construction commencement and expected in-service dates, are listed under Growth Projects – Commercially Secured Projects.


OUTSTANDING SHARE DATA1 PREFERENCE SHARES

Number

Redemption and Conversion

Option Date2,3

Right to convert

Into3,4 Preference Shares, Series A 5,000,000 — — Preference Shares, Series B 18,269,812 June 1, 2022 Series C Preference Shares, Series C 1,730,188 June 1, 2022 Series B Preference Shares, Series D 18,000,000 March 1, 2018 Series E Preference Shares, Series F 20,000,000 June 1, 2018 Series G Preference Shares, Series H 14,000,000 September 1, 2018 Series I Preference Shares, Series J 8,000,000 June 1, 2022 Series K Preference Shares, Series L 16,000,000 September 1, 2022 Series M Preference Shares, Series N 18,000,000 December 1, 2018 Series O Preference Shares, Series P 16,000,000 March 1, 2019 Series Q Preference Shares, Series R 16,000,000 June 1, 2019 Series S Preference Shares, Series 1 16,000,000 June 1, 2018 Series 2 Preference Shares, Series 3 24,000,000 September 1, 2019 Series 4 Preference Shares, Series 5 8,000,000 March 1, 2019 Series 6 Preference Shares, Series 7 10,000,000 March 1, 2019 Series 8 Preference Shares, Series 9 11,000,000 December 1, 2019 Series 10 Preference Shares, Series 11 20,000,000 March 1, 2020 Series 12 Preference Shares, Series 13 14,000,000 June 1, 2020 Series 14 Preference Shares, Series 15 11,000,000 September 1, 2020 Series 16 Preference Shares, Series 17 30,000,000 March 1, 2022 Series 18

COMMON SHARES Number Common Shares - issued and outstanding (voting equity shares) 1,653,649,160 Stock Options - issued and outstanding (23,911,503 vested) 38,100,042

1 Outstanding share data information is provided as at October 20, 2017. 2 All preference shares are non-voting equity shares. Preference Shares, Series A may be redeemed any time at the Company’s

option. For other series of Preference Shares, the Company may, at its option, redeem all or a portion of outstanding Preference Shares for the Base Redemption Value per share plus all accrued and unpaid dividends on the Redemption Option Date and on every fifth anniversary thereafter.

3 The holder will have the right, subject to certain conditions, to convert their shares into Cumulative Redeemable Preference Shares of a specified series on a one-for-one basis on the Conversion Option Date and every fifth anniversary thereafter at an ascribed issue price equal to the Base Redemption Value.

4 On June 1, 2017, 1,730,188 of Series B fixed rate Preference Shares were converted to Series C floating rate Preference Shares based upon preference share holder elections under the terms of the Series B Preference Shares. No Series J or Series L Preference Shares were converted on the June 1, 2017 and September 1, 2017 conversion option dates, respectively.


CONSOLIDATED STATEMENTS OF EARNINGS

Three months ended


September 30, 2017 2016 2017 2016 (unaudited; millions of Canadian dollars, except per share amounts)

Revenues Commodity sales 5,012 6,106 18,498 16,380

Gas distribution sales 573 272 2,783 1,783

Transportation and other services 3,642 2,110 10,208 7,059

9,227 8,488 31,489 25,222

Expenses Commodity costs 5,087 5,950 18,126 15,964

Gas distribution costs 215 99 1,659 1,137

Operating and administrative 1,587 1,101 4,784 3,201

Depreciation and amortization 848 562 2,388 1,676

Asset impairment — 992 — 992

7,737 8,704 26,957 22,970

1,490 (216 ) 4,532 2,252 Income from equity investments 280 133 752 322

Other income/(expense) 225 (10 ) 439 240

Interest expense (653) (397 ) (1,704) (1,178 ) 1,342 (490 ) 4,019 1,636 Income tax recovery/(expense) (Note 12) (327) 253 (818) (174 ) Earnings/(loss) 1,015 (237 ) 3,201 1,462 (Earnings)/loss attributable to noncontrolling interests


Earnings/(loss) attributable to Enbridge Inc. 847 (30 ) 2,568 1,628 Preference share dividends (82) (73 ) (246) (217 ) Earnings/(loss) attributable to Enbridge Inc. common

shareholders 765

(103 ) 2,322

1,411

Earnings/(loss) per common share attributable to Enbridge Inc. common shareholders (Note 4) 0.47

(0.11 ) 1.57

1.56

Diluted earnings/(loss) per common share attributable to Enbridge Inc. common shareholders (Note 4) 0.47

(0.11 ) 1.56

1.55

See accompanying notes to the interim consolidated financial statements.


CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Three months ended


September 30, 2017 2016 2017 2016 (unaudited; millions of Canadian dollars)

Earnings/(loss) 1,015 (237 ) 3,201 1,462

Other comprehensive income/(loss), net of tax Change in unrealized gain/(loss) on cash flow hedges 97 8 10 (669 ) Change in unrealized gain/(loss) on net investment

hedges 285

(54 ) 505

317

Other comprehensive income/(loss) from equity investees 1

(1 ) 9

(2 )

Reclassification to earnings of (gain)/loss on cash flow hedges (14) 33

93

58

Reclassification to earnings of pension and other postretirement benefits (OPEB) amounts 6

4

13

13

Foreign currency translation adjustments (2,057) 174 (3,068) (1,142 ) Other comprehensive income/(loss), net of tax (1,682) 164 (2,438) (1,425 ) Comprehensive income/(loss) (667) (73 ) 763 37 Comprehensive (income)/loss attributable to

noncontrolling interests and redeemable noncontrolling interests 155

190

(204) 360

Comprehensive income/(loss) attributable to Enbridge Inc. (512) 117

559

397

Preference share dividends (82) (73 ) (246) (217 ) Comprehensive income/(loss) attributable to Enbridge

Inc. common shareholders (594) 44 313

180



CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

Nine months ended

September 30, 2017 2016

(unaudited; millions of Canadian dollars, except per share amounts) Preference shares

Balance at beginning and end of period 7,255 6,515 Common shares

Balance at beginning of period 10,492 7,391 Common shares issued — 2,241 Common shares issued in Merger Transaction (Note 5) 37,429 — Dividend reinvestment and share purchase plan 889 591 Shares issued on exercise of stock options 58 39

Balance at end of period 48,868 10,262 Additional paid-in capital

Balance at beginning of period 3,399 3,301 Stock-based compensation 70 38 Fair value of outstanding earned stock-based compensation from Merger Transaction (Note 5) 77 — Options exercised (70) (19 ) Enbridge Energy Company, Inc. common control transaction 78 — Dilution loss on Enbridge Energy Partners, L.P. issuance of A units (522) — Dilution gains and other 62 90

Balance at end of period 3,094 3,410 Retained earnings/(deficit)

Balance at beginning of period (716) 142 Earnings attributable to Enbridge Inc. 2,568 1,628 Preference share dividends (246) (217 ) Common share dividends declared (2,552) (1,448 ) Dividends paid to reciprocal shareholder 22 20 Redemption value adjustment attributable to redeemable noncontrolling interests 232 (843 ) Adjustment for the recognition of unutilized tax deductions for stock-based compensation 41 — Adjustment relating to equity method investment — (28 )

Balance at end of period (651) (746 ) Accumulated other comprehensive income/(loss) (Note 9)

Balance at beginning of period 1,058 1,632 Other comprehensive loss attributable to Enbridge Inc. common shareholders, net of tax (2,009) (1,231 )

Balance at end of period (951) 401 Reciprocal shareholding

Balance at beginning of period (102) (83 ) Issuance of treasury stock — (19 )

Balance at end of period (102) (102 ) Total Enbridge Inc. shareholders’ equity 57,513 19,740 Noncontrolling interests

Balance at beginning of period 577 1,300 Earnings/(loss) attributable to noncontrolling interests 452 (186 ) Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax

Change in unrealized loss on cash flow hedges (13) (140 ) Foreign currency translation adjustments (446) (50 ) Reclassification to earnings of loss on cash flow hedges 29 31

(430) (159 ) Comprehensive income/(loss) attributable to noncontrolling interests 22 (345 ) Noncontrolling interests resulting from Merger Transaction (Note 5) 8,877 — Enbridge Energy Company, Inc. common control transaction (331) — Distributions (634) (538 ) Contributions 498 28 Dilution gain on Enbridge Energy Partners, L.P. issuance of A units 832 — Deconsolidation of Sabal Trail Transmission, LLC (2,318) — Disposition of Olympic Pipeline (24) — Other (16) (6 )

Balance at end of period 7,483 439 Total equity 64,996 20,179 Dividends paid per common share 1.803 1.590



CONSOLIDATED STATEMENTS OF CASH FLOWS

Three months ended


September 30, 2017 2016 2017 2016

(unaudited; millions of Canadian dollars) Operating activities

Earnings/(loss) 1,015 (237 ) 3,201 1,462 Adjustments to reconcile earnings/(loss) to net cash provided

by operating activities: Depreciation and amortization 848 562 2,388 1,676 Deferred income taxes (recovery)/expense 309 (267 ) 725 81 Changes in unrealized gain on derivative instruments, net

(Note 11) (345) (67 ) (1,243) (832 )

Earnings from equity investments (280) (141 ) (752) (505 ) Distributions from equity investments 346 236 859 603 Impairment — 992 — 1,179 (Gain)/loss on disposition (33) 3 (116) 3 Hedge ineffectiveness (Note 11) (4) 17 (3) 48 Inventory revaluation allowance 33 64 49 242 Unrealized intercompany foreign exchange (gain)/loss 6 (2 ) 20 53 Other 49 61 66 233

Changes in environmental liabilities, net of recoveries (2) 2 (97) 16 Changes in operating assets and liabilities (409) (301 ) 146 (106 )

Net cash provided by operating activities 1,533 922 5,243 4,153 Investing activities

Capital expenditures (1,946) (1,004 ) (5,868) (3,963 ) Joint venture financing 18 7 (16) 2 Long-term investments (224) (129 ) (2,984) (376 ) Distributions from equity investments in excess of cumulative

earnings 23

— 62

—

Restricted long-term investments (11) (14 ) (44) (42 ) Additions to intangible assets (205) (22 ) (668) (78 ) Acquisition — (65 ) — (604 ) Cash acquired in Merger Transaction (Note 5) — — 614 — Proceeds from disposition 180 16 622 16 Reimbursement of capital expenditures — — 212 — Affiliate loans, net (12) (5 ) (19) (120 ) Changes in restricted cash 5 (52 ) 26 (35 )

Net cash used in investing activities (2,172) (1,268 ) (8,063) (5,200 ) Financing activities

Net change in short-term borrowings 452 (13 ) 758 (74 ) Net change in commercial paper and credit facility draws (817) 32 463 (374 ) Debenture and term note issues, net of issue costs 4,001 1,098 7,176 1,098 Debenture and term note repayments (2,262) (301 ) (4,433) (724 ) Purchase of interest in consolidated subsidiary — — (227) — Contributions from noncontrolling interests 45 — 498 28 Distributions to noncontrolling interests (248) (176 ) (634) (538 ) Contributions from redeemable noncontrolling interests 14 12 614 579 Distributions to redeemable noncontrolling interests (63) (53 ) (180) (148 ) Common shares issued 13 7 22 2,240 Preference share dividends (82) (73 ) (246) (217 ) Common share dividends (650) (300 ) (1,663) (857 )

Net cash provided by financing activities 403 233 2,148 1,013 Effect of translation of foreign denominated cash and cash

equivalents (45) 5 (77) (33 )

Decrease in cash and cash equivalents (281) (108 ) (749) (67 ) Cash and cash equivalents at beginning of period 1,026 695 1,494 654 Cash and cash equivalents at end of period 745 587 745 587



CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

September 30,

2017 December 31,

2016 (unaudited; millions of Canadian dollars; number of shares in millions)

Assets Current assets

Cash and cash equivalents 745 1,494 Restricted cash 102 68 Accounts receivable and other 5,174 4,978 Accounts receivable from affiliates 65 14 Inventory 1,707 1,233

7,793 7,787 Property, plant and equipment, net 96,305 64,284 Long-term investments 16,319 6,836 Restricted long-term investments 253 90 Deferred amounts and other assets 5,950 3,113 Intangible assets, net 3,009 1,573 Goodwill 32,638 78 Deferred income taxes 1,067 1,170 Assets held for sale 107 278 Total assets 163,441 85,209 Liabilities and equity Current liabilities

Short-term borrowings 1,424 351 Accounts payable and other 7,249 7,295 Accounts payable to affiliates 126 122 Interest payable 573 333 Environmental liabilities 35 142 Current portion of long-term debt 2,807 4,100

12,214 12,343 Long-term debt 61,434 36,494 Other long-term liabilities 6,644 4,981 Deferred income taxes 14,435 6,036 94,727 59,854 Contingencies (Note 15) Redeemable noncontrolling interests 3,718 3,392 Equity

Share capital Preference shares 7,255 7,255 Common shares (1,653 and 943 outstanding at September 30, 2017 and

December 31, 2016, respectively) 48,868

10,492

Additional paid-in capital 3,094 3,399 Deficit (651) (716) Accumulated other comprehensive income/(loss) (Note 9) (951) 1,058 Reciprocal shareholding (102) (102) Total Enbridge Inc. shareholders’ equity 57,513 21,386 Noncontrolling interests 7,483 577

64,996 21,963 Total liabilities and equity 163,441 85,209

Variable Interest Entities (Note 6) See accompanying notes to the interim consolidated financial statements.


NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited) 1. BASIS OF PRESENTATION The accompanying unaudited interim consolidated financial statements of Enbridge Inc. (Enbridge or the Company) have been prepared in accordance with generally accepted accounting principles in the United States of America (U.S. GAAP) and Regulation S-X for interim consolidated financial information. They do not include all of the information and notes required by U.S. GAAP for annual consolidated financial statements and should therefore be read in conjunction with the Company’s audited consolidated financial statements and notes for the year ended December 31, 2016. In the opinion of management, the interim consolidated financial statements contain all adjustments, consisting only of normal recurring adjustments, necessary to present fairly the Company’s financial position, results of operations and cash flows for the interim periods reported. These interim consolidated financial statements follow the same significant accounting policies as those included in the Company’s annual consolidated financial statements for the year ended December 31, 2016, except for the adoption of new standards (Note 2) and the presentation of Cash and cash equivalents to include Bank indebtedness, as discussed below. Amounts are stated in Canadian dollars unless otherwise noted. The Company’s operations and earnings for interim periods can be affected by seasonal fluctuations within the gas distribution utility businesses, as well as other factors such as the supply of and demand for crude oil and natural gas, and may not be indicative of annual results. Effective September 30, 2017, the Company combined Cash and cash equivalents and amounts previously presented as Bank indebtedness where the corresponding bank accounts are subject to cash pooling arrangements. As at September 30, 2017, $1.0 billion (December 31, 2016 - $0.6 billion) of Bank indebtedness has been combined within Cash and cash equivalents in the Company's Consolidated Statements of Financial Position. Net cash provided by financing activities in the Company's Consolidated Statements of Cash Flows for the three and nine month periods ended September 30, 2016 have been reduced by $113 million and $88 million, respectively, to reflect this change. 2. CHANGES IN ACCOUNTING POLICIES ADOPTION OF NEW STANDARDS Simplifying the Measurement of Goodwill Impairment Effective January 1, 2017, the Company early adopted Accounting Standards Update (ASU) 2017-04 and applied the standard on a prospective basis. Under the new guidance, goodwill impairment will now be measured by the amount by which a reporting unit’s carrying value exceeds its fair value; this amount should not exceed the carrying amount of goodwill. The adoption of the pronouncement did not have a material impact on the Company’s consolidated financial statements. Clarifying the Definition of a Business in an Acquisition Effective January 1, 2017, the Company early adopted ASU 2017-01 on a prospective basis. The new standard was issued with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (disposals) of assets or businesses. The adoption of the pronouncement did not have a material impact on the Company’s consolidated financial statements.


Accounting for Intra-Entity Asset Transfers Effective January 1, 2017, the Company early adopted ASU 2016-16 on a modified retrospective basis. The new standard was issued with the intent of improving the accounting for the income tax consequences of intra-entity asset transfers other than inventory. Under the new guidance, an entity should recognize the income tax consequences of an intra-entity transfer of an asset, other than inventory, when the transfer occurs. The adoption of the pronouncement did not have a material impact on the Company’s consolidated financial statements. Improvements to Employee Share-Based Payment Accounting Effective January 1, 2017, the Company adopted ASU 2016-09 and applied certain amendments on a modified retrospective basis with the remaining amendments applied on a prospective basis. The new standard was issued with the intent of simplifying and improving several aspects of accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The adoption of the pronouncement did not have a material impact on the Company’s consolidated financial statements. Simplifying the Embedded Derivatives Analysis for Debt Instruments Effective January 1, 2017, the Company adopted ASU 2016-06 on a modified retrospective basis. The new guidance simplifies the embedded derivative analysis for debt instruments containing contingent call or put options. The adoption of the pronouncement did not have a material impact on the Company’s consolidated financial statements. FUTURE ACCOUNTING POLICY CHANGES Improvements to Accounting for Hedging Activities ASU 2017-12 was issued in August 2017 with the main objective of better aligning a company’s risk management activities and the resulting hedge accounting reflected in the financial statements. The amendments allow cash flow hedging of contractually specified components in financial and non-financial items and make fair value hedges of interest rate risks more effective in certain circumstances. Under the new guidance, hedge ineffectiveness is no longer required to be measured and hedging instruments’ fair value changes will be recorded in the same income statement line as the hedged item. The ASU also allows the initial quantitative hedge effectiveness assessment to be performed at any time before the end of the quarter in which the hedge is designated. After initial quantitative testing is performed, an ongoing qualitative effectiveness assessment is permitted. The Company is currently assessing the impact of the new standard on the consolidated financial statements. The accounting update is effective for annual and interim periods beginning after December 15, 2018, with early adoption permitted, and is to be applied on a modified retrospective basis. Clarifying Guidance on the Application of Modification Accounting on Stock Compensation ASU 2017-09 was issued in May 2017 with the intent to clarify the scope of modification accounting and when it should be applied to a change to the terms or conditions of a share based payment award. Under the new guidance, modification accounting is required for all changes to share based payment awards, unless all of the following are met: 1) there is no change to the fair value of the award, 2) the vesting conditions have not changed, and 3) the classification of the award as an equity instrument or a debt instrument has not changed. The accounting update is effective for annual periods beginning after December 15, 2017 and is to be applied on a prospective basis. The adoption of ASU 2017-09 is not expected to have a material impact on the Company’s consolidated financial statements. Amending the Amortization Period for Certain Callable Debt Securities Purchased at a Premium ASU 2017-08 was issued in March 2017 with the intent of shortening the amortization period to the earliest call date for certain callable debt securities held at a premium. The Company is currently assessing the impact of the new standard on the consolidated financial statements. The accounting update is effective for annual and interim periods beginning after December 15, 2018 and is to be applied on a modified retrospective basis.


Improving the Presentation of Net Periodic Benefit Cost Related to Defined Benefit Plans ASU 2017-07 was issued in March 2017 primarily to improve the income statement presentation of the components of net periodic pension cost and net periodic postretirement benefit cost for an entity’s sponsored defined benefit pension and other postretirement plans. In addition, only the service-cost component of net benefit cost is eligible for capitalization. The accounting update is effective for annual and interim periods beginning after December 15, 2017 and is to be applied on a retrospective basis for the statement of earnings presentation component and a prospective basis for the capitalization component. The Company is currently assessing the impact of the new standard on the consolidated financial statements. Clarifying Guidance on Derecognition and Partial Sales of Nonfinancial Assets ASU 2017-05 was issued in February 2017 with the intent of clarifying the scope of asset derecognition guidance and accounting for partial sales of nonfinancial assets. The ASU clarifies the scope provisions of nonfinancial assets and how to allocate consideration to each distinct asset, and amends the guidance for derecognition of a distinct nonfinancial asset in partial sale transactions. The Company is currently assessing the impact of the new standard on the consolidated financial statements. The accounting update is effective for annual and interim periods beginning after December 15, 2017 and is to be applied on a retrospective or modified retrospective basis. Accounting for Credit Losses ASU 2016-13 was issued in June 2016 with the intent of providing financial statement users with more useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. Current treatment uses the incurred loss methodology for recognizing credit losses that delays the recognition until it is probable a loss has been incurred. The amendment adds a new impairment model, known as the current expected credit loss model, which is based on expected losses rather than incurred losses. Under the new guidance, an entity recognizes as an allowance its estimate of expected credit losses, which the Financial Accounting Standards Board believes will result in more timely recognition of such losses. The Company is currently assessing the impact of the new standard on its consolidated financial statements. The accounting update is effective for annual and interim periods beginning on or after December 15, 2019. Recognition of Leases ASU 2016-02 was issued in February 2016 with the intent to increase transparency and comparability among organizations. It requires lessees of operating lease arrangements to recognize lease assets and lease liabilities on the statement of financial position and disclose additional key information about lease agreements. The accounting update also replaces the current definition of a lease and requires that an arrangement be recognized as a lease when a customer has the right to obtain substantially all of the economic benefits from the use of an asset, as well as the right to direct the use of the asset. The Company is currently gathering a complete inventory of its lease contracts in order to assess the impact of the new standard on its consolidated financial statements. The accounting update is effective for fiscal years beginning after December 15, 2018 and is to be applied using a modified retrospective approach. Revenue from Contracts with Customers ASU 2014-09 was issued in 2014 with the intent of significantly enhancing consistency and comparability of revenue recognition practices across entities and industries. The new standard establishes a single, principles-based five-step model to be applied to all contracts with customers and introduces new and enhanced disclosure requirements. The standard is effective for fiscal years beginning after December 15, 2017. The new revenue standard permits either a full retrospective method of adoption with restatement of all prior periods presented, or a modified retrospective method with the cumulative effect of applying the new standard recognized as an adjustment to opening retained earnings in the period of adoption. The Company has decided to adopt the new revenue standard using the modified retrospective method.


The Company has reviewed a sample of its revenue contracts in order to evaluate the effect of the new standard on its revenue recognition practices. Based on the Company’s initial assessment, the application of the standard may result in a change in presentation in the Gas Distribution business related to payments to customers under the earnings sharing mechanism which are currently shown as an expense in the Consolidated Statements of Earnings. Under the new standard, these payments would be reflected as a reduction of revenue. Additionally, estimates of variable consideration which will be required under the new standard as well as the allocation of the transaction price for certain revenue contracts, may result in changes to the pattern or timing of revenue recognition for those contracts. While the Company has not yet completed the assessment, the Company’s preliminary view is that it does not expect these changes will have a material impact on revenue or earnings/(loss). The Company has also developed and tested processes to generate the disclosures required under the new standard.

3. SEGMENTED INFORMATION

Liquids

Pipelines

Gas Pipelines

and Processing

Gas Distribution

Green Power and

Transmission Energy

Services Eliminations

and Other Consolidated Three months ended September 30, 2017 (millions of Canadian dollars) Revenues 2,324 1,862 716 109 4,284 (68) 9,227 Commodity and gas distribution costs (5) (703) (242) 1 (4,421) 68 (5,302) Operating and administrative (770) (498) (246) (42) (11) (20) (1,587) Depreciation and amortization (377) (241) (157) (48) — (25) (848)

1,172 420 71 20 (148) (45) 1,490 Income/(loss) from equity investments 118 162 (3) — 3 — 280 Other income/(expense) 36 33 15 — (5) 146 225 Earnings/(loss) before interest and

income taxes 1,326

615

83

20

(150) 101

1,995

Interest expense (653) Income tax expense (327) Earnings 1,015 Capital expenditures1 529 1,052 302 64 — 22 1,969

Liquids

Pipelines

Gas Pipelines

and Processing

Gas Distribution

Green Power and

Transmission Energy


and Other Consolidated Three months ended September 30, 2016 (millions of Canadian dollars) Revenues 1,913 713 355 118 5,471 (82) 8,488 Commodity and gas distribution costs (4) (531) (110) 1 (5,485) 80 (6,049) Operating and administrative (745) (112) (131) (41) (12) (60) (1,101) Depreciation and amortization (343) (73) (87) (47) — (12) (562) Asset impairment (992) — — — — — (992)

(171) (3) 27 31 (26) (74) (216) Income/(loss) from equity investments 87 66 (21) 1 — — 133 Other income/(expense) (3) 4 14 2 1 (28) (10) Earnings/(loss) before interest and

income taxes (87) 67

20

34

(25) (102) (93)

Interest expense (397) Income tax recovery 253 Loss (237) Capital expenditures1 732 18 190 57 — 7 1,004


Liquids

Pipelines

Gas Pipelines

and Processing

Gas Distribution

Green Power and

Transmission Energy


and Other Consolidated Nine months ended September 30, 2017 (millions of Canadian dollars) Revenues 6,722 5,051 3,322 386 16,272 (264) 31,489 Commodity and gas distribution costs (13) (2,053) (1,740) 4 (16,251) 268 (19,785) Operating and administrative (2,214) (1,305) (676) (123) (34) (432) (4,784) Depreciation and amortization (1,118) (627) (426) (149) (1) (67) (2,388)

3,377 1,066 480 118 (14) (495) 4,532 Income/(loss) from equity investments 312 427 10 2 5 (4) 752 Other income/(expense) 33 143 21 1 (3) 244 439 Earnings/(loss) before interest and

income taxes 3,722

1,636

511

121

(12) (255) 5,723

Interest expense (1,704) Income tax expense (818) Earnings 3,201 Capital expenditures1 1,723 3,081 794 293 1 90 5,982

Liquids

Pipelines

Gas Pipelines

and Processing

Gas Distribution

Green Power and

Transmission Energy


and Other Consolidated Nine months ended September 30, 2016 (millions of Canadian dollars) Revenues 6,269 1,980 2,134 374 14,715 (250) 25,222 Commodity and gas distribution costs (9) (1,477) (1,169) 4 (14,698) 248 (17,101) Operating and administrative (2,191) (358) (409) (118) (46) (79) (3,201) Depreciation and amortization (1,025) (222) (251) (142) (1) (35) (1,676) Asset impairment (992) — — — — — (992)

2,052 (77) 305 118 (30) (116) 2,252 Income/(loss) from equity investments 117 200 6 2 (3) — 322 Other income/(expense) (1) 24 31 4 (5) 187 240 Earnings/(loss) before interest and

income taxes 2,168

147

342

124

(38) 71

2,814

Interest expense (1,178) Income tax expense (174) Earnings 1,462 Capital expenditures1 3,134 151 582 74 — 23 3,964

1 Includes allowance for equity funds used during construction.

TOTAL ASSETS

September 30,

2017 1

December 31, 2016

(unaudited; millions of Canadian dollars)

Liquids Pipelines 55,472 52,007

Gas Pipelines and Processing 45,580 11,182

Gas Distribution 19,562 10,132

Green Power and Transmission 6,011 5,571

Energy Services 1,302 1,951

Eliminations and Other 2,924 4,366

130,851 85,209

1 Excludes goodwill allocation of $32.6 billion, in connection with the Merger Transaction (Note 5).


4. EARNINGS PER COMMON SHARE BASIC Earnings per common share is calculated by dividing earnings attributable to common shareholders by the weighted average number of common shares outstanding. The weighted average number of common shares outstanding has been reduced by the Company’s pro-rata weighted average interest in its own common shares of 13 million (2016 - 13 million) for the three and nine months ended September 30, 2017, resulting from the Company’s reciprocal investment in Noverco Inc. DILUTED The treasury stock method is used to determine the dilutive impact of stock options. This method assumes any proceeds from the exercise of stock options would be used to purchase common shares at the average market price during the period. Weighted average common shares outstanding used to calculate basic and diluted earnings per common share are as follows:

Three months ended


September 30, 2017 2016 2017 2016 (number of common shares in millions)

Weighted average common shares outstanding 1,635 922 1,482 905

Effect of dilutive options 7 — 8 8

Diluted weighted average common shares outstanding 1,642 922 1,490 913

For the three and nine months ended September 30, 2017, 12,917,175 and 13,293,044 anti-dilutive stock options (2016 - 37,497,343 and 11,880,242) with a weighted average exercise price of $56.79 and $57.50 (2016 - $41.90 and $52.30) were excluded from the diluted earnings per common share calculation. 5. ACQUISITION AND DISPOSITIONS ACQUISITION Spectra Energy Corp On February 27, 2017, Enbridge and Spectra Energy Corp (Spectra Energy) combined in a stock-for-stock merger transaction (the Merger Transaction) for a purchase price of $37.5 billion. Under the terms of the Merger Transaction, Spectra Energy shareholders received 0.984 shares of Enbridge for each share of Spectra Energy common stock that they owned, giving Enbridge 100% ownership of Spectra Energy. Consideration offered to complete the Merger Transaction included 691 million common shares of Enbridge at US$41.34 per share, based on the February 24, 2017 closing price on the New York Stock Exchange (NYSE), for a total value of $37,429 million in common shares issued to Spectra Energy shareholders, plus approximately $3 million in cash in lieu of any fractional shares, and 3.5 million share options with a fair value of $77 million, that were exchanged for Spectra Energy’s outstanding stock compensation awards. Spectra Energy, through its subsidiaries and equity affiliates, owns and operates a large and diversified portfolio of complementary natural gas-related energy assets and is one of North America’s leading natural gas infrastructure companies. Spectra Energy also owns and operates a crude oil pipeline system that connects Canadian and United States producers to refineries in the United States Rocky Mountain and Midwest regions. The combination brings together two highly complementary platforms to create North America’s largest energy infrastructure company and meaningfully enhances customer optionality, positioning the Company for long-term growth opportunities, and strengthening the Company’s balance sheet.


The Merger Transaction has been accounted for as a business combination under the acquisition method of accounting as prescribed by Accounting Standards Codification (ASC) 805 Business Combinations. The acquired tangible and intangible assets and assumed liabilities are recorded at their estimated fair values at the date of acquisition. The purchase price allocation was prepared on a preliminary basis and is subject to change as additional information becomes available concerning the fair value and tax basis of the assets acquired, as well as rate-regulated balances. The allocation of goodwill to reporting units is outstanding at the date of issuance of the Company’s consolidated financial statements. Any adjustments to the purchase price allocation will be made as soon as practicable but no later than one year from the date of acquisition. The following table summarizes the estimated fair values that were assigned to the net assets of Spectra Energy:

February 27, 2017 (millions of Canadian dollars)

Fair value of net assets acquired: Current assets (a) 2,365

Property, plant and equipment, net (b) 35,510

Restricted long-term investments 144

Long-term investments (c) 5,000

Deferred amounts and other assets (d) 2,920

Intangible assets, net (e) 1,288

Current liabilities (3,434 ) Long-term debt (d) (21,925 ) Other long-term liabilities (1,983 ) Deferred income taxes (8,331 ) Noncontrolling interests (f) (8,877 )

2,677 Goodwill (g) 34,832

37,509

Purchase price: Common shares 37,429

Cash 3

Fair value of outstanding earned stock compensation awards recorded in Additional paid-in capital 77

37,509

a) Accounts receivable is comprised primarily of customer trade receivables and the natural gas

imbalance balance. As such, the fair value of accounts receivable approximates the net carrying value of $1,174 million. The gross amount due of $1,190 million, of which $16 million is not expected to be collected, is included in current assets.

b) The Company has applied the valuation methodologies described in ASC 820 Fair Value

Measurements and Disclosures, to value the property, plant and equipment purchased. The fair value of Spectra Energy’s rate-regulated property, plant and equipment was determined using a market participant perspective, which is their carrying amount. The fair value of the remaining non-regulated property, plant and equipment was determined primarily using variations of the income approach, which is based on the present value of the future after-tax cash flows attributable to each non-regulated asset. Some of the more significant assumptions inherent in the development of the values, from the perspective of a market participant, include, but are not limited to, the amount and timing of projected future cash flows (including revenue and profitability); the discount


rate selected to measure the risks inherent in the future cash flows; the assessment of the asset’s life cycle; the competitive trends impacting the asset; and customer turnover.

In September 2017, Spectra Energy's right-of-way agreements were reclassified from intangible assets to property, plant and equipment to conform the presentation of these agreements with the Company's accounting policy pertaining to rights-of-way. The purchase price allocation above reflects this reclassification, which amounted to $830 million as at February 27, 2017. There is no change in the amortization period for the right-of-way agreements as a result of this reclassification.

c) Long-term investments represent Spectra Energy’s 50% equity investment in DCP Midstream, LLC

(DCP Midstream), Gulfstream Natural Gas System, L.L.C., Nexus Gas Transmission, LLC (Nexus), Steckman Ridge LP, Islander East Pipeline Company, L.L.C., Southeast Supply Header L.L.C., and 20% equity interest in PennEast Pipeline Company LLC (PennEast). The fair value of these investments was determined using an income approach.

d) Fair value of long-term debt was determined based on the current underlying Government of

Canada and United States Treasury interest rates on the corresponding bonds, as well as an implied credit spread based on current market conditions and resulted in an increase in the book value of debt of $1.5 billion. The fair value adjustment to long-term debt related to rate-regulated entities of $629 million also results in a regulatory offset in Deferred amounts and other assets in the Consolidated Statements of Financial Position.

e) Intangible assets consist of customer relationships in the non-regulated business, which represent

the underlying relationship from long-term agreements with customers that are capitalized upon acquisition, determined using the income approach. Intangible assets are amortized on a straight-line basis over their expected lives.

Intangible assets decreased by $830 million as at February 27, 2017 due to a reclassification to property, plant and equipment, as discussed under (b) above.

f) The fair value of Spectra Energy’s noncontrolling interests includes approximately 78.4 million

Spectra Energy Partners, LP (SEP) common units outstanding to the public, valued at the February 24, 2017 closing price of US$44.88 per common unit on the NYSE, and units held by third parties in Maritimes & Northeast Pipeline, L.L.C., Sabal Trail Transmission, LLC (Sabal Trail) and Algonquin Gas Transmission, L.L.C., valued based on the underlying net assets of each reporting unit and preferred stock held by third parties in Union Gas Limited (Union Gas) and Westcoast Energy Inc.

During the three months ended September 30, 2017, the Company finalized its fair value remeasurement of Sabal Trail, which resulted in an increase to both noncontrolling interests and goodwill of $85 million as at February 27, 2017.

g) The Company recorded $34.8 billion in goodwill, which is primarily related to expected synergies

from the Merger Transaction. The goodwill balance recognized is not deductible for tax purposes. Factors that contributed to the goodwill include the opportunity to expand Enbridge’s natural gas pipelines segment, the potential for cost and supply chain optimization synergies, existing assembled assets and work force that cannot be duplicated at the same cost by a new entrant, franchise rights and other intangibles not separately identifiable because they are inextricably linked to the provision of regulated utility service and the enhanced scale and geographic diversity which provide greater optionality and platforms for future growth.

Goodwill increased by $85 million due to the finalization of Sabal Trail's fair value measurement, as discussed under (f) above.


Acquisition-related expenses incurred to date were approximately $231 million. Costs incurred for the three and nine months ended September 30, 2017 of $2 million and $180 million, respectively (December 31, 2016 - $51 million) are included in Operating and administrative expense in the Consolidated Statements of Earnings. For the three months ending December 31, 2017 and for the years ending December 31, 2018 through 2021, the Company has future minimum lease payment commitments for operating leases of $12 million, $48 million, $48 million, $43 million, $39 million respectively, and $189 million thereafter, as a result of the Merger Transaction. Upon completion of the Merger Transaction, the Company began consolidating Spectra Energy. Since the closing date of February 27, 2017 through September 30, 2017, Spectra Energy has generated approximately $3,868 million in revenues and $537 million in earnings. The following supplemental pro forma consolidated financial information of the Company for the three and nine months ended September 30, 2017 and 2016 includes the results of operations for Spectra Energy as if the Merger Transaction had been completed on January 1, 2016.

Three months ended



Revenues 9,227 9,852 32,780 29,900 Earnings attributable to Enbridge Inc. common

shareholders1 766

192 2,695

2,259

1 Merger Transaction costs of $2 million and $180 million (after-tax $1 million and $131 million) were excluded from earnings for the three and nine months ended September 30, 2017, respectively.

ASSETS HELD FOR SALE St. Lawrence Gas Company, Inc. In August 2017, the Company entered into an agreement to sell the issued and outstanding shares of St. Lawrence Gas Company, Inc. (St. Lawrence Gas) for cash proceeds of approximately $88 million (US$70 million). Subject to regulatory approval and certain pre-closing conditions, the transaction is expected to close in the first half of 2018. As at September 30, 2017, St. Lawrence Gas, which is a part of the Company's Gas Distribution segment, was classified as held for sale in the Consolidated Statements of Financial Position. DISPOSITIONS Olympic Pipeline On July 31, 2017, the Company completed the sale of its interest in Olympic Pipeline for cash proceeds of approximately $203 million (US$160 million). A gain on disposal of $27 million (US$21 million) was included in Other income/(expense) in the Consolidated Statements of Earnings. This interest was a part of the Company’s Liquids Pipelines segment. Sandpiper Project During the nine months ended September 30, 2017, the Company sold unused pipe related to the Sandpiper project for cash proceeds of approximately $136 million (US$103 million). A gain on disposal of $75 million (US$57 million) was included in Operating and administrative expense in the Consolidated Statements of Earnings. These assets were a part of the Company’s Liquids Pipelines segment. Ozark Pipeline On March 1, 2017, the Company completed the sale of the Ozark Pipeline assets to a subsidiary of MPLX LP for cash proceeds of approximately $294 million (US$219 million), including reimbursement of costs. A


gain on disposal of $14 million (US$10 million) was included in Operating and administrative expense in the Consolidated Statements of Earnings. These assets were a part of the Company’s Liquids Pipelines segment.

6. VARIABLE INTEREST ENTITIES The following variable interest entities (VIEs) represents current year additions, including both consolidated and unconsolidated VIEs acquired in connection with the Merger Transaction (Note 5). CONSOLIDATED VARIABLE INTEREST ENTITIES Enbridge Holdings (DakTex) L.L.C. Enbridge Holdings (DakTex) L.L.C. (DakTex) is owned 75% by a wholly-owned subsidiary of the Company and 25% by Enbridge Energy Partners, L.P. (EEP), through which the Company has an effective 27.6% interest in the equity investment, Bakken Pipeline System (Note 7). EEP is the primary beneficiary because it has the power to direct DakTex’s activities that most significantly impact its economic performance. The Company consolidates EEP and by extension also consolidates DakTex. ACQUIRED CONSOLIDATED VARIABLE INTEREST ENTITIES Spectra Energy Partners, LP The Company acquired a 75% ownership in SEP through the Merger Transaction. SEP is a natural gas and crude oil infrastructure master limited partnership and is considered a VIE as its limited partners do not have substantive kick-out rights or participating rights. The Company is the primary beneficiary of SEP because it has the power to direct SEP’s activities that most significantly impact its economic performance. Valley Crossing Pipeline, LLC Valley Crossing Pipeline, LLC (Valley Crossing), a wholly-owned subsidiary of the Company, is constructing a natural gas pipeline to transport natural gas within Texas. Valley Crossing is considered a VIE due to insufficient equity at risk to finance its activities. The Company is the primary beneficiary of Valley Crossing because it has the power to direct Valley Crossing’s activities that most significantly impact its economic performance. Other Limited Partnerships By virtue of a lack of substantive kick-out rights and participating rights, substantially all limited partnerships wholly-owned or majority owned by Enbridge and/or its subsidiaries, acquired through the Merger Transaction, are considered acquired VIEs. As these entities are wholly-owned or majority owned and directed by Enbridge with no third parties having the ability to direct any of the significant activities, the Company is considered the primary beneficiary.


The following table includes assets to be used to settle liabilities of Enbridge’s consolidated VIEs and liabilities of Enbridge’s consolidated VIEs for which creditors do not have recourse to the Company’s general credit as the primary beneficiary. These assets and liabilities are included in the Consolidated Statements of Financial Position.

September 30, 2017 (millions of Canadian dollars)

Assets Cash and cash equivalents 385

Accounts receivable and other 1,110

Inventory 304

1,799 Property, plant and equipment, net 27,274

Long-term investments 5,760

Restricted long-term investments 79

Deferred amounts and other assets 1,041

Intangible assets, net 149

36,102

Liabilities Short-term borrowings 670

Accounts payable and other 1,529

Interest payable 95

Current portion of long-term debt 1,126

3,420 Long-term debt 12,707

Other long-term liabilities 1,440

Deferred income taxes 683

18,250 Net assets before noncontrolling interests 17,852

ACQUIRED UNCONSOLIDATED VARIABLE INTEREST ENTITIES The following unconsolidated VIEs are included within Long-term investments in the table above. Sabal Trail Transmission, LLC SEP owns a 50% interest in Sabal Trail, a joint venture that operates a pipeline originating in Alabama that transports natural gas to Florida. On July 3, 2017, the Company discontinued its consolidation of Sabal Trail and accounts for its interest under the equity method. Sabal Trail is a VIE due to insufficient equity at risk to finance its activities. The Company is not the primary beneficiary because the power to direct Sabal Trail's activities that most significantly impact its economic performance is shared. For details on the impact of the deconsolidation of Sabal Trail, refer to Note 7 - Long-term Investments. Nexus Gas Transmission, LLC SEP owns a 50% equity investment in Nexus, a joint venture that is constructing a natural gas pipeline from Ohio to Michigan and continuing on to Ontario, Canada. Nexus is a VIE due to insufficient equity at risk to finance its activities. The Company is not the primary beneficiary because the power to direct Nexus’ activities that most significantly impact its economic performance is shared.


PennEast Pipeline Company, LLC SEP owned a 10% equity investment in PennEast, which was increased to 20% in June 2017. PennEast is constructing a natural gas pipeline from northeastern Pennsylvania to New Jersey. PennEast is a VIE due to insufficient equity at risk to finance its activities. The Company is not the primary beneficiary since it does not have the power to direct PennEast’s activities that most significantly impact its economic performance. The carrying amount of the Company’s interest and its maximum exposure to loss in material unconsolidated VIEs are presented below:

Carrying Amount of

Investment in VIE

Enbridge’s Maximum

Exposure to Loss September 30, 2017


Sabal Trail Transmission, LLC 2,373 2,562

Nexus Gas Transmission, LLC 668 1,313

PennEast Pipeline Company, LLC 59 343

3,100 4,218

7. LONG-TERM INVESTMENTS SABAL TRAIL TRANSMISSION, LLC On July 3, 2017, Sabal Trail was placed into service. In accordance with the Sabal Trail LLC Agreement, upon the in-service date, the power to direct Sabal Trail’s activities becomes shared with its members. The Company is no longer the primary beneficiary and deconsolidated the assets, liabilities and noncontrolling interests related to Sabal Trail as at the in-service date. At deconsolidation, the Company’s 50% interest in Sabal Trail was recorded at its fair value of $2.3 billion (US$1.9 billion), which approximated its carrying value as a long-term equity investment. As a result, there was no gain or loss recognized for the three months ended September 30, 2017 related to the remeasurement of the retained equity interest to its fair value. The fair value was determined using the income approach which is based on the present value of the future cash flows. The Company's interest in Sabal Trail is accounted for under the equity method of accounting and is presented within the Company's Gas Pipelines and Processing segment. As at the in-service date, the carrying value of the Company's investment in Sabal Trail included a basis difference of $485 million (US$388 million) related to the original purchase price allocation, which represents the excess of its carrying value over its proportionate share of the investees' net assets. The basis difference represents equity goodwill and will not be amortized. For the three and nine months ended September 30, 2017, the Company recognized equity earnings of $18 million (US$14 million). BAKKEN PIPELINE SYSTEM On February 15, 2017, EEP acquired an effective 27.6% interest in the Dakota Access and Energy Transfer Crude Oil Pipelines (collectively, the Bakken Pipeline System) for a purchase price of $2.0 billion (US$1.5 billion). The Bakken Pipeline System was placed into service on June 1, 2017. It connects the Bakken formation in North Dakota to markets in the eastern Petroleum Administration for Defense Districts and the United States Gulf Coast, providing customers with access to premium markets at a competitive cost. For details regarding the Company’s funding arrangement, refer to Note 10 - Noncontrolling Interests.


The Company accounts for its interest in the Bakken Pipeline System under the equity method of accounting. For the three and nine months ended September 30, 2017, the Company recognized $27 million (US$22 million) and $35 million (US$28 million), respectively, in equity earnings for this investment, net of amortization of the purchase price basis difference. The Company’s equity investment includes the excess of the purchase price over the underlying net book value, or basis difference, of the investees’ assets at the purchase date, which is comprised of $19 million (US$14 million) in goodwill and $1,210 million (US$931 million) in amortizable assets included within the Liquids Pipelines segment. The Company amortized $13 million (US$10 million) and $17 million (US$13 million) for the three and nine months ended September 30, 2017, respectively, which was recorded as a reduction to equity earnings. HOHE SEE OFFSHORE WIND PROJECT On February 8, 2017, Enbridge acquired an effective 50% interest in EnBW Hohe See GmbH & Co. KG (Hohe See), a German offshore wind development company. Hohe See is co-owned by Enbridge and Energie Baden-Wurttenberg AG, a major German electric utility. Construction of the wind farm began in March 2017 and is expected to be fully operational in late 2019. As at September 30, 2017, the carrying amount of the investment is $523 million (€354 million), which is included within the Green Power and Transmission segment, and represents Enbridge’s portion of the costs incurred to date.

8. DEBT CREDIT FACILITIES

September 30, 2017

Maturity

Dates Total

Facilities Draws1 Available


Enbridge Inc.2 2019-2022 7,349 5,089 2,260

Enbridge (U.S.) Inc. 2018-2019 3,665 786 2,879

Enbridge Energy Partners, L.P.3 2019-2020 3,283 1,683 1,600

Enbridge Gas Distribution Inc. 2019 1,016 766 250

Enbridge Income Fund 2020 1,500 611 889

Enbridge Pipelines (Southern Lights) L.L.C. 2019 25 — 25

Enbridge Pipelines Inc. 2019 3,000 1,499 1,501

Enbridge Southern Lights LP 2019 5 — 5

Spectra Energy Partners, LP 4,5 2022 3,127 2,544 583

Westcoast Energy Inc.5 2021 400 156 244

Union Gas Limited5 2021 700 670 30

Total committed credit facilities 24,070 13,804 10,266

1 Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility. 2 Includes $260 million of commitments that expire in 2018. 3 Includes $219 million (US$175 million) of commitments that expire in 2018. 4 Includes $237 million (US$190 million) of commitments that expire in 2021. 5 Committed credit facilities acquired on February 27, 2017 in conjunction with the Merger Transaction (Note 5).

During the third quarter of 2017, the Company completed the following term debt offerings: • US$1.4 billion of senior unsecured notes, which consist of two US$700 million tranches that

mature in five and 10 years with fixed interest rates of 2.9% and 3.7%, respectively. Approximately US$1.4 billion of the net proceeds were used to complete a cash tender offer for and follow-up redemption of Spectra Energy Capital, LLC's (Spectra Capital) senior unsecured notes, as discussed below.

• US$1.0 billion of fixed-to-floating rate subordinated notes that mature in 60 years and are callable on or after year 10. For the initial 10 years, the notes carry a fixed interest rate of 5.5%.


Subsequently, the interest rate will be set to equal the three-month London Interbank Offered Rate (LIBOR) plus a margin of 342 basis points from year 10 to 30, and a margin of 417 basis points from year 30 to 60.

• $1.0 billion of fixed-to-floating rate subordinated notes that mature in 60 years and are callable on or after year 10. For the initial 10 years, the notes carry a fixed interest rate of 5.4%. Subsequently, the interest rate will be set to equal the three-month Bankers' Acceptance Rate plus a margin of 325 basis points from year 10 to 30, and a margin of 400 basis points from year 30 to 60.

On July 7, 2017 and September 8, 2017, Enbridge and Spectra Capital completed a cash tender offer for and follow-up redemption of Spectra Capital’s outstanding 8.0% senior unsecured notes due 2019. The aggregate principal amount tendered and redeemed was US$500 million. Spectra Capital paid the consenting note holders an aggregate cash consideration of US$581 million. On July 13, 2017, pursuant to a cash tender offer, Spectra Capital purchased a portion of the principal amount of its outstanding senior unsecured notes carrying interest rates ranging from 3.3% to 7.5%, with maturities ranging from one to 21 years. The principal amount tendered and accepted was US$761 million. Spectra Capital paid the consenting note holders an aggregate cash consideration of US$857 million. The loss on debt extinguishment of $50 million (US$38 million), net of the fair value adjustment recorded upon completion of the Merger Transaction, was reported within Interest expense in the Consolidated Statements of Earnings. During the second quarter of 2017, the Company completed the following term debt offerings:

• $1.2 billion of unsecured medium-term notes with maturity dates ranging from 2022 to 2044 and fixed interest rates ranging from 3.2% to 4.6%.

• $750 million of unsecured floating rate notes that mature in 2019 and carry an interest rate equal to the three-month Bankers' Acceptance Rate plus 59 basis points.

• US$500 million of unsecured floating rate notes that mature in 2020 and carry an interest rate equal to the three-month LIBOR plus 70 basis points.

During the second quarter of 2017, SEP issued US$400 million of unsecured floating rate notes that mature in 2020 and carry an interest rate equal to the three-month LIBOR plus 70 basis points. During the first quarter of 2017, the Company established a five-year, term credit facility for $239 million (¥20,000 million) with a syndicate of Japanese banks. In addition to the committed credit facilities noted above, the Company also has $791 million (December 31, 2016 - $335 million) of uncommitted demand credit facilities, of which $412 million (December 31, 2016 - $177 million) were unutilized as at September 30, 2017. Certain credit facilities serve as a back-stop to the commercial paper programs and the Company has the option to extend the facilities, which are currently set to mature from 2018 to 2022. As at September 30, 2017, commercial paper and credit facility draws, net of short-term borrowings and non-revolving credit facilities that mature within one year, of $12,267 million (December 31, 2016 - $7,344 million) are supported by the availability of long-term committed credit facilities and therefore have been classified as long-term debt.


ANNUAL MATURITIES AND INTEREST OBLIGATIONS1

20172 2018 2019 2020 2021 Thereafter (millions of Canadian dollars)

Annual maturities3 617 2,819 4,065 4,877 2,725 37,405 Interest obligations4 584 2,373 2,176 2,020 1,857 19,821

1 This table excludes the debt issuances that occurred subsequent to September 30, 2017 (Note 16). 2 For the three months ending December 31, 2017. 3 Includes the Company’s debenture, term note and non-revolving credit facility maturities. 4 Includes the Company’s debentures and term notes bearing interest at fixed and floating rates.

As a result of the Merger Transaction, the debt of the Company increased by $22,978 million on the acquisition date. Accordingly, annual debt repayment amounts have also increased and have been reflected in the table above. The Company has the ability under certain debt facilities to call and repay the obligations prior to scheduled maturities. Therefore, the actual timing of future cash repayments could be materially different than presented above. DEBT COVENANTS The Company was deemed to be in compliance with all terms and conditions of its committed credit facility agreements and term debt indentures as at September 30, 2017.

9. COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME Changes in Accumulated other comprehensive income/(loss) (AOCI) attributable to Enbridge Inc. common shareholders for the nine months ended September 30, 2017 and 2016 are as follows:

Cash Flow

Hedges

Net Investment

Hedges

Cumulative Translation Adjustment

Equity Investees

Pension and

OPEB Adjustment Total

(millions of Canadian dollars) Balance at January 1, 2017 (746) (629) 2,700 37 (304) 1,058 Other comprehensive income/(loss) retained in

AOCI 29

496

(2,616) (4) —

(2,095)

Other comprehensive (income)/loss reclassified to earnings

Interest rate contracts1 104 — — — — 104 Commodity contracts2 (5) — — — — (5) Foreign exchange contracts3 (2) — — — — (2) Other contracts4 (3) — — — — (3) Amortization of pension and OPEB actuarial loss

and prior service cost5 —

—

—

—

21

21

123 496 (2,616) (4) 21 (1,980) Tax impact

Income tax on amounts retained in AOCI (9) 9 — 13 — 13 Income tax on amounts reclassified to earnings (34) — — — (8) (42)

(43) 9 — 13 (8) (29) Balance at September 30, 2017 (666) (124) 84 46 (291) (951)


Cash Flow

Hedges

Net Investment

Hedges

Cumulative Translation Adjustment

Equity Investees

Pension and

OPEB Adjustment Total

(millions of Canadian dollars) Balance at January 1, 2016 (688) (795) 3,365 37 (287) 1,632 Other comprehensive income/(loss) retained in

AOCI (714) 328

(1,086) (7) —

(1,479)

Other comprehensive (income)/loss reclassified to earnings

Interest rate contracts1 85 — — — — 85 Commodity contracts2 (7) — — — — (7) Foreign exchange contracts3 1 — — — — 1 Other contracts4 (36) — — — — (36) Amortization of pension and OPEB actuarial loss

and prior service cost5 —

—

—

—

18

18

(671) 328 (1,086) (7) 18 (1,418) Tax impact

Income tax on amounts retained in AOCI 216 (11) — 5 — 210 Income tax on amounts reclassified to earnings (18) — — — (5) (23)

198 (11) — 5 (5) 187 Balance at September 30, 2016 (1,161) (478) 2,279 35 (274) 401

1 Reported within Interest expense in the Consolidated Statements of Earnings. 2 Reported within Commodity costs in the Consolidated Statements of Earnings. 3 Reported within Other income/(expense) in the Consolidated Statements of Earnings. 4 Reported within Operating and administrative expense in the Consolidated Statements of Earnings. 5 These components are included in the computation of net periodic benefit costs and are reported within Operating and

administrative expense in the Consolidated Statements of Earnings.

10. NONCONTROLLING INTERESTS UNITED STATES SPONSORED VEHICLE STRATEGY On April 28, 2017, Enbridge completed a strategic review of EEP. The following actions, together with the measures announced in January 2017 and disclosed in the Company’s annual consolidated financial statements for 2016, were taken. As a result of these actions, the Company recorded an increase in Noncontrolling interests of $458 million, inclusive of foreign currency translation adjustments, and a decrease in Additional paid-in capital of $421 million, net of deferred income taxes of $253 million. Acquisition of Midcoast Assets and Privatization of Midcoast Energy Partners, L.P. On April 27, 2017, Enbridge completed its previously-announced merger through a wholly-owned subsidiary, through which it privatized Midcoast Energy Partners, L.P. (MEP) by acquiring all of the outstanding publicly-held common units of MEP for total consideration of approximately US$170 million. On June 28, 2017, Enbridge, through a wholly-owned subsidiary, acquired all of EEP’s interest in the Midcoast gas gathering and processing business for cash consideration of US$1.3 billion plus existing indebtedness of MEP of US$953 million. As a result of the above transactions, 100% of the Midcoast gas gathering and processing business is now owned by Enbridge. EEP Strategic Restructuring Actions On April 27, 2017, EEP redeemed all of its outstanding Series 1 Preferred Units held by Enbridge at face value of US$1.2 billion through the issuance of 64.3 million Class A common units to Enbridge. Further, Enbridge irrevocably waived all of its rights associated with its ownership of 66.1 million Class D units and 1,000 Incentive Distribution Units of EEP, in exchange for the issuance of 1,000 Class F units. The Class F units are entitled to (i) 13% of all distributions in excess of US$0.295 per EEP unit, but equal to or less than US$0.35 per EEP unit, and (ii) 23% of all distributions in excess of US$0.35 per EEP unit. The irrevocable waiver is effective with respect to distributions declared with a record date after April 27, 2017.


In connection with these strategic restructuring actions, EEP reduced its quarterly distribution from US$0.583 per unit to US$0.35 per unit. Further, in conjunction with the restructuring actions, EEP terminated a receivable purchase agreement with an Enbridge wholly-owned special purpose entity. Finalization of Bakken Pipeline System Joint Funding Agreement On April 27, 2017, Enbridge entered into a joint funding arrangement with EEP whereby Enbridge owns 75% and EEP owns 25% of the combined 27.6% effective interest in the Bakken Pipeline System. Under this arrangement, EEP has retained a five-year option to acquire an additional 20% interest. On finalization of this joint funding arrangement, EEP repaid the outstanding balance on its US$1.5 billion credit agreement with Enbridge, which it had drawn upon to fund the initial purchase. REDEEMABLE NONCONTROLLING INTERESTS Enbridge Income Fund Holdings Inc. Secondary Offering On April 18, 2017, the Company and Enbridge Income Fund Holdings Inc. (ENF) completed the secondary offering of 17,347,750 ENF common shares to the public at a price of $33.15 per share, for gross proceeds to Enbridge of approximately $0.6 billion (the Secondary Offering). To effect the Secondary Offering, Enbridge exchanged 21,657,617 Enbridge Income Fund units it owned for an equivalent amount of ENF common shares. In order to maintain its 19.9% interest in ENF, Enbridge retained 4,309,867 of the common shares it received in the exchange, and sold the balance through the Secondary Offering. Enbridge used the proceeds from the Secondary Offering to pay down short-term debt, pending reinvestment by the Company in its growing portfolio of secured projects. Upon closing of the Secondary Offering, the Company’s total economic interest in ENF decreased from 86.9% to 84.6%. As a result of the Secondary Offering, the Company recorded a decrease in Redeemable noncontrolling interests of $87 million and an increase in Additional paid-in capital of $87 million.

11. RISK MANAGEMENT AND FINANCIAL INSTRUMENTS MARKET RISK The Company’s earnings, cash flows and other comprehensive income (OCI) are subject to movements in foreign exchange rates, interest rates, commodity prices and the Company’s share price (collectively, market risk). Formal risk management policies, processes and systems have been designed to mitigate these risks. The following summarizes the types of market risks to which the Company is exposed and the risk management instruments used to mitigate them. The Company uses a combination of qualifying and non-qualifying derivative instruments to manage the risks noted below. Foreign Exchange Risk The Company generates certain revenues, incurs expenses, and holds a number of investments and subsidiaries that are denominated in currencies other than Canadian dollars. As a result, the Company’s earnings, cash flows and OCI are exposed to fluctuations resulting from foreign exchange rate variability. The Company has implemented a policy whereby, at a minimum, it hedges a level of foreign currency denominated earnings exposures over a five-year forecast horizon. A combination of qualifying and non-qualifying derivative instruments are used to hedge anticipated foreign currency denominated revenues and expenses, and to manage variability in cash flows. The Company hedges certain net investments in United States dollar denominated investments and subsidiaries using foreign currency derivatives and United States dollar denominated debt. Interest Rate Risk The Company’s earnings and cash flows are exposed to short-term interest rate variability due to the regular repricing of its variable rate debt, primarily commercial paper. Pay fixed-receive floating interest rate swaps and options are used to hedge against the effect of future interest rate movements. The Company has implemented a program to significantly mitigate the impact of short-term interest rate


volatility on interest expense via execution of floating to fixed interest rate swaps with an average swap rate of 2.5%. As a result of the Merger Transaction, the Company is exposed to changes in the fair value of the fixed rate debt that arise as a result of the changes in market interest rates. Pay floating-receive fixed interest rate swaps are used to hedge against the future changes to the fair value of the fixed rate debt. The Company has implemented a program to significantly mitigate the impact of fluctuations in the fair value of the fixed rate debt via execution of fixed to floating interest rate swaps with an average swap rate of 2.2%. The Company’s earnings and cash flows are also exposed to variability in longer term interest rates ahead of anticipated fixed rate term debt issuances. Forward starting interest rate swaps are used to hedge against the effect of future interest rate movements. The Company has implemented a program to significantly mitigate its exposure to long-term interest rate variability on select forecast term debt issuances via execution of floating to fixed interest rate swaps with an average swap rate of 3.6%. The Company also monitors its debt portfolio mix of fixed and variable rate debt instruments to maintain a consolidated portfolio of debt within its Board of Directors approved policy limit of a maximum of 25% floating rate debt as a percentage of total debt outstanding. The Company primarily uses qualifying derivative instruments to manage interest rate risk. Commodity Price Risk The Company’s earnings and cash flows are exposed to changes in commodity prices as a result of its ownership interests in certain assets and investments, as well as through the activities of its energy services subsidiaries. These commodities include natural gas, crude oil, power and natural gas liquids (NGL). The Company employs financial derivative instruments to fix a portion of the variable price exposures that arise from physical transactions involving these commodities. The Company uses primarily non-qualifying derivative instruments to manage commodity price risk. Emission Allowance Price Risk Emission allowance price risk is the risk of gain or loss due to changes in the market price of emission allowances that the gas distribution business of the Company is required to purchase for itself and most of its customers to meet greenhouse gas compliance obligations. Similar to the gas supply procurement framework, the Ontario Energy Board’s (OEB) framework for emission allowance procurement allows recovery of fluctuations in emission allowance prices in customer rates, subject to OEB approval. Equity Price Risk Equity price risk is the risk of earnings fluctuations due to changes in the Company’s share price. The Company has exposure to its own common share price through the issuance of various forms of stock-based compensation, which affect earnings through revaluation of the outstanding units every period. The Company uses equity derivatives to manage the earnings volatility derived from one form of stock-based compensation, restricted share units. The Company uses a combination of qualifying and non-qualifying derivative instruments to manage equity price risk.


TOTAL DERIVATIVE INSTRUMENTS The following table summarizes the Consolidated Statements of Financial Position location and carrying value of the Company’s derivative instruments. The Company generally has a policy of entering into individual International Swaps and Derivatives Association, Inc. (ISDA) agreements, or other similar derivative agreements, with the majority of its derivative counterparties. These agreements provide for the net settlement of derivative instruments outstanding with specific counterparties in the event of bankruptcy or other significant credit event, and would reduce the Company’s credit risk exposure on derivative asset positions outstanding with the counterparties in those circumstances. The following table summarizes the maximum potential settlement in the event of these specific circumstances. All amounts are presented gross in the Consolidated Statements of Financial Position.

September 30, 2017

Derivative Instruments

Used as Cash Flow

Hedges


Used as Net Investment

Hedges


Used as Fair Value

Hedges

Non- Qualifying Derivative

Instruments

Total Gross Derivative

Instruments as

Presented

Amounts Available for

Offset

Total Net Derivative

Instruments

(millions of Canadian dollars) Accounts receivable and other

Foreign exchange contracts 5 4 — 72 81 (62) 19 Interest rate contracts 1 — 4 — 5 (1) 4 Commodity contracts 7 — — 172 179 (94) 85

13 4 4 244 265 (157) 108 Deferred amounts and other assets

Foreign exchange contracts 1 1 — 147 149 (133) 16 Interest rate contracts 3 — 11 — 14 (3) 11 Commodity contracts 19 — — 17 36 (28) 8 Other contracts 1 — — 1 2 — 2

24 1 11 165 201 (164) 37 Accounts payable and other

Foreign exchange contracts (5) (105) — (422) (532) 62 (470) Interest rate contracts (244) — (4) (133) (381) 1 (380) Commodity contracts — — — (279) (279) 94 (185) Other contracts — — — (5) (5) — (5)

(249) (105) (4) (839) (1,197) 157 (1,040) Other long-term liabilities

Foreign exchange contracts (4) (9) — (1,201) (1,214) 133 (1,081) Interest rate contracts (201) — — (194) (395) 3 (392) Commodity contracts — — — (165) (165) 28 (137)

(205) (9) — (1,560) (1,774) 164 (1,610) Total net derivative asset/(liability)

Foreign exchange contracts (3) (109) — (1,404) (1,516) — (1,516) Interest rate contracts (441) — 11 (327) (757) — (757) Commodity contracts 26 — — (255) (229) — (229) Other contracts 1 — — (4) (3) — (3)

(417) (109) 11 (1,990) (2,505) — (2,505)


December 31, 2016


Used as Cash Flow

Hedges


Used as Net Investment

Hedges

Non- Qualifying Derivative

Instruments


Instruments as

Presented

Amounts Available for

Offset

Total Net Derivative

Instruments

(millions of Canadian dollars) Accounts receivable and other

Foreign exchange contracts 101 3 5 109 (103) 6 Interest rate contracts 3 — — 3 (3) — Commodity contracts 9 — 232 241 (125) 116

113 3 237 353 (231) 122 Deferred amounts and other assets

Foreign exchange contracts 1 3 69 73 (72) 1 Interest rate contracts 8 — — 8 (6) 2 Commodity contracts 7 — 61 68 (22) 46 Other contracts 1 — 1 2 — 2

17 3 131 151 (100) 51 Accounts payable and other

Foreign exchange contracts — (268) (727) (995) 103 (892) Interest rate contracts (452) — (131) (583) 3 (580) Commodity contracts — — (359) (359) 125 (234) Other contracts (1) — (3) (4) — (4)

(453) (268) (1,220) (1,941) 231 (1,710) Other long-term liabilities

Foreign exchange contracts — (68) (1,961) (2,029) 72 (1,957) Interest rate contracts (268) — (205) (473) 6 (467) Commodity contracts — — (211) (211) 22 (189)

(268) (68) (2,377) (2,713) 100 (2,613) Total net derivative asset/(liability)

Foreign exchange contracts 102 (330) (2,614) (2,842) — (2,842) Interest rate contracts (709) — (336) (1,045) — (1,045) Commodity contracts 16 — (277) (261) — (261) Other contracts — — (2) (2) — (2)

(591) (330) (3,229) (4,150) — (4,150)


The following table summarizes the maturity and notional principal or quantity outstanding related to the Company’s derivative instruments.

September 30, 2017 2017 2018 2019 2020 2021 Thereafter Foreign exchange contracts - United States dollar forwards

- purchase (millions of United States dollars) 519

2

2

2

—

—

Foreign exchange contracts - United States dollar forwards - sell (millions of United States dollars) 1,648

3,041

3,246

3,258

567

224

Foreign exchange contracts - British pound (GBP) forwards - purchase (millions of GBP) 30

6

—

—

—

—

Foreign exchange contracts - GBP forwards - sell (millions of GBP) —

—

89

25

27

177

Foreign exchange contracts - Euro forwards - purchase (millions of Euro) 68

256

340

—

—

—

Foreign exchange contracts - Euro forwards - sell (millions of Euro) —

—

—

35

152

952

Foreign exchange contracts - Japanese yen forwards - purchase (millions of yen) —

—

32,662

—

—

20,000

Interest rate contracts - short-term pay fixed rate (millions of Canadian dollars) 1,517

4,945

1,583

214

95

292

Interest rate contracts - long-term receive fixed rate (millions of Canadian dollars) 473

1,519

1,016

821

432

400

Interest rate contracts - long-term debt pay fixed rate (millions of Canadian dollars) 3,426

2,683

756

—

—

—

Equity contracts (millions of Canadian dollars) 48 47 37 8 — — Commodity contracts - natural gas (billions of cubic feet) (21) (60) (41) (5) — (2 ) Commodity contracts - crude oil (millions of barrels) 1 (7) — — — — Commodity contracts - NGL (millions of barrels) (5) (10) — — — — Commodity contracts - power (megawatt per hour (MW/H)) 44 42 51 55 (3) (43 )

December 31, 2016 2017 2018 2019 2020 2021 Thereafter Foreign exchange contracts - United States dollar forwards

- purchase (millions of United States dollars) 991

2

2

2

—

—

Foreign exchange contracts - United States dollar forwards - sell (millions of United States dollars) 4,369

2,768

2,943

2,722

566

223

Foreign exchange contracts - GBP forwards - purchase (millions of GBP) 91

6

—

—

—

—

Foreign exchange contracts - GBP forwards - sell (millions of GBP) —

—

89

25

27

144

Foreign exchange contracts - Japanese yen forwards - purchase (millions of yen) —

—

32,662

—

—

—

Interest rate contracts - short-term pay fixed rate (millions of Canadian dollars) 6,713

5,161

1,581

153

100

300

Interest rate contracts - long-term pay fixed rate (millions of Canadian dollars) 3,998

2,743

768

—

—

—

Equity contracts (millions of Canadian dollars) 48 40 — — — — Commodity contracts - natural gas (billions of cubic feet) (93) (42) (17) (9) — — Commodity contracts - crude oil (millions of barrels) (11) (9) — — — — Commodity contracts - NGL (millions of barrels) (8) (6) — — — — Commodity contracts - power (MW/H) 40 30 31 35 (3) (43 )


The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income

The following table presents the effect of cash flow hedges and net investment hedges on the Company’s consolidated earnings and consolidated comprehensive income, before the effect of income taxes.

Three months ended



Amount of unrealized gain/(loss) recognized in OCI Cash flow hedges

Foreign exchange contracts (2) 2 (1) (31 ) Interest rate contracts 83 108 28 (896 ) Commodity contracts — 12 12 10

Other contracts 16 9 1 46

Net investment hedges Foreign exchange contracts 148 (14 ) 221 58

245 117 261 (813 )

Amount of (gain)/loss reclassified from AOCI to earnings (effective portion)

Foreign exchange contracts1 (3) — (104) 2

Interest rate contracts2 50 51 134 102

Commodity contracts3 — (2 ) (4) (8 ) Other contracts4 (11) (5 ) 2 (35 )

36 44 28 61

Amount of (gain)/loss reclassified from AOCI to earnings (ineffective portion and amount excluded from effectiveness testing)


(1) 17 5 48

1 Reported within Transportation and other services revenues and Other income/(expense) in the Consolidated Statements of Earnings.

2 Reported within Interest expense in the Consolidated Statements of Earnings. 3 Reported within Transportation and other services revenues, Commodity sales revenues, Commodity costs and Operating and

administrative expense in the Consolidated Statements of Earnings. 4 Reported within Operating and administrative expense in the Consolidated Statements of Earnings.

The Company estimates that a loss of $48 million of AOCI related to cash flow hedges will be reclassified to earnings in the next 12 months. Actual amounts reclassified to earnings depend on the foreign exchange rates, interest rates and commodity prices in effect when derivative contracts that are currently outstanding mature. For all forecasted transactions, the maximum term over which the Company is hedging exposures to the variability of cash flows is 27 months as at September 30, 2017. Fair Value Derivatives For interest rate derivative instruments that are designated and qualify as fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged risk is included in Interest expense in the Consolidated Statements of Earnings. During the three and nine months ended September 30, 2017, the Company recognized an unrealized loss of nil and $1 million, respectively (2016 - nil) on the derivative and an unrealized gain of $1 million and $2 million, respectively (2016 - nil) on the hedged item in earnings. During the three and nine months ended September 30, 2017, the Company recognized a realized gain of $2 million and $2 million (2016 - nil) on the derivative and a realized loss of $2 million and $2 million (2016 - nil) on the hedged item in earnings. The difference in the amounts, if any, represents hedge ineffectiveness.


Non-Qualifying Derivatives The following table presents the unrealized gains and losses associated with changes in the fair value of the Company’s non-qualifying derivatives.

Three months ended



Foreign exchange contracts1 503 49 1,210 1,093


Commodity contracts3 (160) (47 ) 22 (345 ) Other contracts4 3 5 (2) 16

Total unrealized derivative fair value gain, net 345 67 1,243 832

1 For the respective nine months ended periods, reported within Transportation and other services revenues (2017 - $726 million gain; 2016 - $578 million gain) and Other income/(expense) (2017 - $484 million gain; 2016 - $515 million gain) in the Consolidated Statements of Earnings.

2 Reported as an (increase)/decrease within Interest expense in the Consolidated Statements of Earnings. 3 For the respective nine months ended periods, reported within Transportation and other services revenues (2017 - $85 million

loss; 2016 - $30 million loss), Commodity sales (2017 - $67 million gain; 2016 - $367 million loss), Commodity costs (2017 - $22 million gain; 2016 - $73 million gain) and Operating and administrative expense (2017 - $18 million gain; 2016 - $21 million loss) in the Consolidated Statements of Earnings.

4 Reported within Operating and administrative expense in the Consolidated Statements of Earnings.

LIQUIDITY RISK

Liquidity risk is the risk that the Company will not be able to meet its financial obligations, including commitments and guarantees, as they become due. In order to mitigate this risk, the Company forecasts cash requirements over a 12 month rolling time period to determine whether sufficient funds will be available and maintains substantial capacity under its committed bank lines of credit to address any contingencies. The Company’s primary sources of liquidity and capital resources are funds generated from operations, the issuance of commercial paper and draws under committed credit facilities and long-term debt, which includes debentures and medium-term notes. The Company also maintains current shelf prospectuses with securities regulators, which enables, subject to market conditions, ready access to either the Canadian or United States public capital markets. In addition, the Company maintains sufficient liquidity through committed credit facilities with a diversified group of banks and institutions which, if necessary, enables the Company to fund all anticipated requirements for approximately one year without accessing the capital markets. The Company is deemed to be in compliance with all the terms and conditions of its committed credit facility agreements and term debt indentures as at September 30, 2017. As a result, all credit facilities are available to the Company and the banks are obligated to fund and have been funding the Company under the terms of the facilities. CREDIT RISK

Entering into derivative financial instruments may result in exposure to credit risk from the possibility that a counterparty will default on its contractual obligations. In order to mitigate this risk, the Company enters into risk management transactions primarily with institutions that possess investment grade credit ratings. Credit risk relating to derivative counterparties is mitigated by credit exposure limits and contractual requirements, netting arrangements, and ongoing monitoring of counterparty credit exposure using external credit rating services and other analytical tools.


The Company had group credit concentrations and maximum credit exposure, with respect to derivative instruments, in the following counterparty segments:

September 30,

2017 December 31,

2016 (millions of Canadian dollars)

Canadian financial institutions 85 39

United States financial institutions 34 179

European financial institutions 152 106

Asian financial institutions 3 1

Other1 160 162

434 487

1 Other is comprised of commodity clearing house and physical natural gas and crude oil counterparties.

As at September 30, 2017, the Company had provided letters of credit totalling $191 million in lieu of providing cash collateral to its counterparties pursuant to the terms of the relevant ISDA agreements. The Company held no cash collateral on derivative asset exposures as at September 30, 2017 and December 31, 2016. Gross derivative balances have been presented without the effects of collateral posted. Derivative assets are adjusted for non-performance risk of the Company’s counterparties using their credit default swap spread rates, and are reflected at fair value. For derivative liabilities, the Company’s non-performance risk is considered in the valuation. Credit risk also arises from trade and other long-term receivables, and is mitigated through credit exposure limits and contractual requirements, assessment of credit ratings and netting arrangements. Within Enbridge Gas Distribution Inc. and Union Gas, credit risk is mitigated by the utilities' large and diversified customer base and the ability to recover an estimate for doubtful accounts through the ratemaking process. The Company actively monitors the financial strength of large industrial customers and, in select cases, has obtained additional security to minimize the risk of default on receivables. Generally, the Company classifies and provides for receivables older than 30 days as past due. The maximum exposure to credit risk related to non-derivative financial assets is their carrying value. FAIR VALUE MEASUREMENTS The Company’s financial assets and liabilities measured at fair value on a recurring basis include derivative instruments. The Company also discloses the fair value of other financial instruments not measured at fair value. The fair value of financial instruments reflects the Company’s best estimates of market value based on generally accepted valuation techniques or models and are supported by observable market prices and rates. When such values are not available, the Company uses discounted cash flow analysis from applicable yield curves based on observable market inputs to estimate fair value. FAIR VALUE OF FINANCIAL INSTRUMENTS The Company categorizes its derivative instruments measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. Level 1 Level 1 includes derivatives measured at fair value based on unadjusted quoted prices for identical assets and liabilities in active markets that are accessible at the measurement date. An active market for a derivative is considered to be a market where transactions occur with sufficient frequency and volume to provide pricing information on an ongoing basis. The Company’s Level 1 instruments consist primarily of exchange-traded derivatives used to mitigate the risk of crude oil price fluctuations.


Level 2 Level 2 includes derivative valuations determined using directly or indirectly observable inputs other than quoted prices included within Level 1. Derivatives in this category are valued using models or other industry standard valuation techniques derived from observable market data. Such valuation techniques include inputs such as quoted forward prices, time value, volatility factors and broker quotes that can be observed or corroborated in the market for the entire duration of the derivative. Derivatives valued using Level 2 inputs include non-exchange traded derivatives such as over-the-counter foreign exchange forward and cross currency swap contracts, interest rate swaps, physical forward commodity contracts, as well as commodity swaps and options for which observable inputs can be obtained. The Company has also categorized the fair value of its held to maturity preferred share investment and long-term debt as Level 2. The fair value of the Company’s held to maturity preferred share investment is primarily based on the yield of certain Government of Canada bonds. The fair value of the Company’s long-term debt is based on quoted market prices for instruments of similar yield, credit risk and tenor. Level 3 Level 3 includes derivative valuations based on inputs which are less observable, unavailable or where the observable data does not support a significant portion of the derivatives’ fair value. Generally, Level 3 derivatives are longer dated transactions, occur in less active markets, occur at locations where pricing information is not available or have no binding broker quote to support Level 2 classification. The Company has developed methodologies, benchmarked against industry standards, to determine fair value for these derivatives based on extrapolation of observable future prices and rates. Derivatives valued using Level 3 inputs primarily include long-dated derivative power contracts and NGL and natural gas contracts, basis swaps, commodity swaps, power and energy swaps, as well as options. The Company does not have any other financial instruments categorized in Level 3. The Company uses the most observable inputs available to estimate the fair value of its derivatives. When possible, the Company estimates the fair value of its derivatives based on quoted market prices. If quoted market prices are not available, the Company uses estimates from third party brokers. For non-exchange traded derivatives classified in Levels 2 and 3, the Company uses standard valuation techniques to calculate the estimated fair value. These methods include discounted cash flows for forwards and swaps and Black-Scholes-Merton pricing models for options. Depending on the type of derivative and nature of the underlying risk, the Company uses observable market prices (interest, foreign exchange, commodity and share price) and volatility as primary inputs to these valuation techniques. Finally, the Company considers its own credit default swap spread as well as the credit default swap spreads associated with its counterparties in its estimation of fair value.


The Company has categorized its derivative assets and liabilities measured at fair value as follows:

September 30, 2017 Level 1 Level 2 Level 3


Instruments (millions of Canadian dollars)

Financial assets Current derivative assets

Foreign exchange contracts — 81 — 81

Interest rate contracts — 5 — 5

Commodity contracts 5 33 141 179

5 119 141 265

Long-term derivative assets Foreign exchange contracts — 149 — 149


Commodity contracts — 2 34 36

Other contracts — 2 — 2

— 167 34 201

Financial liabilities Current derivative liabilities

Foreign exchange contracts — (532) — (532) Interest rate contracts — (381) — (381) Commodity contracts (13) (52) (214) (279) Other contracts — (5) — (5)

(13) (970) (214) (1,197) Long-term derivative liabilities

Foreign exchange contracts — (1,214) — (1,214) Interest rate contracts — (395) — (395) Commodity contracts — (4) (161) (165)

— (1,613) (161) (1,774) Total net financial liability

Foreign exchange contracts — (1,516) — (1,516) Interest rate contracts — (757) — (757) Commodity contracts (8) (21) (200) (229) Other contracts — (3) — (3)

(8) (2,297) (200) (2,505)


December 31, 2016 Level 1 Level 2 Level 3


Instruments (millions of Canadian dollars)

Financial assets Current derivative assets

Foreign exchange contracts — 109 — 109


Commodity contracts 2 86 153 241

2 198 153 353

Long-term derivative assets Foreign exchange contracts — 73 — 73


Commodity contracts — 43 25 68

Other contracts — 2 — 2

— 126 25 151

Financial liabilities Current derivative liabilities

Foreign exchange contracts — (995) — (995) Interest rate contracts — (583) — (583) Commodity contracts (12) (75) (272) (359) Other contracts — (4) — (4)

(12) (1,657) (272) (1,941) Long-term derivative liabilities

Foreign exchange contracts — (2,029) — (2,029) Interest rate contracts — (473) — (473) Commodity contracts — (10) (201) (211)

— (2,512) (201) (2,713) Total net financial asset/(liability)

Foreign exchange contracts — (2,842) — (2,842) Interest rate contracts — (1,045) — (1,045) Commodity contracts (10) 44 (295) (261) Other contracts — (2) — (2)

(10) (3,845) (295) (4,150)


The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments were as follows:

September 30, 2017 Fair

Value Unobservable

Input Minimum

Price/Volatility Maximum

Price/Volatility Weighted

Average Price Unit of

Measurement

(fair value in millions of Canadian dollars) Commodity contracts - financial1

Natural gas 8 Forward gas price 2.94 4.31 3.68 $/mmbtu3 Crude 1 Forward crude price 46.73 51.49 49.70 $/barrel NGL (11 ) Forward NGL price 0.34 2.04 1.19 $/gallon Power (127 ) Forward power price 24.25 62.88 46.77 $/MW/H

Commodity contracts - physical1 Natural gas (38 ) Forward gas price 2.68 8.57 3.28 $/mmbtu3 Crude (34 ) Forward crude price 38.17 70.05 60.91 $/barrel NGL 6 Forward NGL price 0.33 2.01 1.03 $/gallon

Commodity options2 Crude 1 Option volatility 20% 29% 24% NGL (7 ) Option volatility 27% 48% 42% Power 1 Option volatility 27% 47% 32%

(200 )

1 Financial and physical forward commodity contracts are valued using a market approach valuation technique. 2 Commodity options contracts are valued using an option model valuation technique. 3 One million British thermal units (mmbtu).

If adjusted, the significant unobservable inputs disclosed in the table above would have a direct impact on the fair value of the Company’s Level 3 derivative instruments. The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments include forward commodity prices and, for option contracts, price volatility. Changes in forward commodity prices could result in significantly different fair values for the Company’s Level 3 derivatives. Changes in price volatility would change the value of the option contracts. Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of price volatility. Changes in net fair value of derivative assets and liabilities classified as Level 3 in the fair value hierarchy were as follows:

Nine months ended September 30,

2017 2016 (millions of Canadian dollars)

Level 3 net derivative asset/(liability) at beginning of period (295) 54

Total gain/(loss) Included in earnings1 1 (113 ) Included in OCI 11 2

Settlements 83 (127 ) Level 3 net derivative liability at end of period (200) (184 )

1 Reported within Transportation and other services revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings.

The Company’s policy is to recognize transfers as of the last day of the reporting period. There were no transfers between levels as at September 30, 2017 or 2016.


FAIR VALUE OF OTHER FINANCIAL INSTRUMENTS Equity investments in other entities with no actively quoted prices available for fair value measurement are recorded at cost by the Company. The carrying value of all equity investments recognized at cost totalled $107 million as at September 30, 2017 (December 31, 2016 - $110 million). The Company has Restricted long-term investments held in trust totalling $253 million as at September 30, 2017 (December 31, 2016 - $90 million) which are recognized at fair value. The Company has a held to maturity preferred share investment carried at its amortized cost of $357 million as at September 30, 2017 (December 31, 2016 - $355 million). These preferred shares are entitled to a cumulative preferred dividend based on the yield of 10-year Government of Canada bonds plus a margin of 4.38%. As at September 30, 2017, the fair value of this preferred share investment approximates its face value of $580 million (December 31, 2016 - $580 million). As at September 30, 2017, the Company’s long-term debt had a carrying value of $64.3 billion (December 31, 2016 - $40.8 billion) before debt issuance cost and a fair value of $67.3 billion (December 31, 2016 - $43.9 billion). The Company also has noncurrent notes receivable carried at book value recorded in Deferred amounts and other assets in the Consolidated Statements of Financial Position. As at September 30, 2017, the noncurrent notes receivable has a carrying value of $89 million (December 31, 2016 - nil) and a fair value of $89 million (December 31, 2016 - nil). NET INVESTMENT HEDGES The Company has designated a portion of its United States dollar denominated debt, as well as a portfolio of foreign exchange forward contracts, as a hedge of its net investment in United States dollar denominated investments and subsidiaries. During the nine months ended September 30, 2017, the Company recognized an unrealized foreign exchange gain on the translation of United States dollar denominated debt of $350 million (2016 - $241 million) and an unrealized gain on the change in fair value of its outstanding foreign exchange forward contracts of $222 million (2016 - $59 million) in OCI. The Company recognized a realized loss of $128 million (2016 - realized gain of $2 million) in OCI associated with the settlement of foreign exchange forward contracts and recognized a realized gain of $52 million (2016 - $26 million) in OCI associated with the settlement of United States dollar denominated debt that had matured during the period. There was no ineffectiveness during the nine months ended September 30, 2017 (2016 - nil).

12. INCOME TAXES The effective income tax rates for the three and nine months ended September 30, 2017 were 24.4% and 20.4%, respectively (2016 - a recovery of 51.6% and an expense of 10.6%, respectively). The period-over-period change in the effective income tax rates is primarily attributable to the rate-regulated accounting for income taxes and other permanent items relative to the increase in earnings for the three and nine months ended September 30, 2017.


13. PENSION AND OTHER POSTRETIREMENT BENEFITS NET PERIODIC BENEFIT COSTS RECOGNIZED

Three months ended



Service cost 65 40 181 123

Interest cost 46 25 125 74

Expected return on plan assets (71) (38 ) (195) (114 ) Amortization of prior service costs (1) — (1) —

Amortization of actuarial loss 11 8 28 26

Net periodic benefit costs 50 35 138 109

ACQUIRED PENSION PLANS In connection with the Merger Transaction (Note 5), the Company has assumed registered and non-registered pension plans in both Canada and the United States (the Canadian Plans and United States Plans, respectively), which provide either defined benefit or defined contribution pension benefits to employees of the Company. The acquired Canadian Plans provide registered and non-registered, contributory and non-contributory defined benefit plans and defined contribution retirement plans covering substantially all Canadian employees of Spectra Energy. The acquired Canadian defined benefit plans provide retirement benefits based on each plan participant’s years of service and final average earnings. Under the acquired Canadian defined contribution plan, Company contributions are determined according to the terms of the plan and are based on each plan participant’s age, years of service and current eligible earnings. In connection with the Merger Transaction, the Company also assumed non-qualified defined benefit supplemental pensions provided to all employees who retire under a Canadian defined benefit registered pension plan and whose pension is limited by the maximum pension limits under the Income Tax Act (Canada). The acquired United States Plans provide Company-funded defined benefit plans for United States-based employees using a cash balance formula. Under a cash balance formula, a plan participant accumulates a retirement benefit consisting of pay credits that are based upon a percentage of current eligible earnings and current interest credits. The Company also assumed non-qualified, non-contributory and unfunded defined benefit plans, and other non-qualified plans such as savings and deferred compensation plans, covering certain current and former executives based in the United States. These non-qualified pension plans have no plan assets. The acquired OPEB primarily includes supplemental health care and life insurance coverage for qualifying retired employees on a contributory and non-contributory basis. A measurement date of February 27, 2017 was used to determine the plan assets and accrued benefit obligation for the Canadian and United States Plans.


The following is a summary of the fair value of the Canadian and United States Plan and OPEB-related balances assumed at February 27, 2017:

Pension OPEB February 27, 2017 U.S. Canada U.S. Canada (millions of Canadian dollars)

Projected benefit obligation 818 1,505 275 146

Fair value of plan assets 737 1,290 103 —

Underfunded status (81) (215 ) (172) (146 ) Presented as follows:

Deferred amounts and other assets — 23 — —

Accounts payable and other (2) — (3) (4 ) Other long-term liabilities (79) (238 ) (169) (142 )

(81) (215 ) (172) (146 )

The weighted average assumptions made in the measurement of the projected benefit obligations of the assumed pension plans and OPEB are as follows:

Pension OPEB February 27, 2017 U.S. Canada U.S. Canada Discount rate 3.6% 3.8% 3.5% 3.9%Average rate of salary increases 4.0% 3.0%

Medical Cost Trends The assumed rates for the next year used to measure the expected cost of OPEB are as follows:

Medical Cost Trend Rate Assumption for

Next Fiscal Year

Ultimate Medical Cost Trend Rate

Assumption

Year in which Ultimate Medical Cost Trend Rate Assumption is Achieved

Canadian Plans 5% 5% United States Plans 7.5% 4.5% 2037

Acquired Plan Assets Canadian and United States Plan assets are maintained in Master Trusts in both the United States and Canada. The investment objective of the Master Trusts is to achieve reasonable returns on Plan assets, subject to a prudent level of portfolio risk, for the purpose of enhancing the security of benefits for plan participants. The asset allocation targets are set after considering the investment objective and the risk profile with respect to the Plans. Equity securities are held for their high expected return. Other equity and fixed income securities are held for diversification. Investments within asset classes are diversified to achieve broad market participation and reduce the effects of individual investments. Actual asset allocation of investments is regularly reviewed and periodically rebalanced to the targeted allocation when considered appropriate. The Company manages the investment risk of its assumed Canadian and United States Plan funds by setting a long-term asset mix policy for each plan after consideration of: (i) the nature of pension plan liabilities; (ii) the investment horizon of the plan; (iii) the going concern and solvency funded status and cash flow requirements of the plan; (iv) the operating environment and financial situation of the Company and its ability to withstand fluctuations in pension contributions; and (v) the future economic and capital markets outlook with respect to investment returns, volatility of returns and correlation between assets. The overall expected rate of return is based on the asset allocation targets with estimates for returns on equity and fixed income securities based on long-term expectations.


Expected Rate of Return on Acquired Plan Assets

February 27, 2017 Pension OPEB Canadian Plans 6.4% United States Plans 5.5% 4.8%

Target Mix for Acquired Plan Assets

Canadian Plans

United States Plans

Equity securities 55.0% 30.0%Fixed income securities 45.0% 60.0%Other 0.0% 10.0%

Major Categories of Acquired Plan Assets Acquired Plan assets are invested primarily in readily marketable investments with constraints on the credit quality of fixed income securities. As at February 27, 2017, the acquired pension assets were invested 48.9% in equity securities, 46.7% in fixed income securities, and 4.4% in cash and cash equivalents and other. The OPEB assets were invested 38.8% in equity securities, 47.6% in fixed income securities, and 13.6% in cash and cash equivalents and other. The following table summarizes the Company’s acquired pension and OPEB financial instruments at fair value:

February 27, 2017 Level 11 Level 22 Level 33 Total (millions of Canadian dollars)

Pension Cash and cash equivalents 4 — — 4

Fixed income securities 946 — — 946

Equity 580 412 — 992 Other — — 85 85

OPEB Cash and cash equivalents 6 — — 6

Fixed income securities 37 12 — 49

Equity 21 19 — 40 Other — — 8 8

1 Level 1 assets include assets with quoted prices in active markets for identical assets. 2 Level 2 assets include assets with significant observable inputs. 3 Level 3 assets include assets with significant unobservable inputs.

Acquired Plan Contributions by the Company

Year ended December 31, 2017 Pension OPEB (millions of Canadian dollars) Contributions expected to be paid 25 8

Benefits Expected to be Paid by the Company Related to the Acquired Plans

Year ended December 31, 2017 2018 2019 2020 2021 2022-2026 (millions of Canadian dollars) Expected future benefit payments 124 150 151 157 153 820


14. RELATED PARTY TRANSACTIONS Related party transactions are conducted in the normal course of business and unless otherwise noted, are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties. The following denotes material related party transactions and their impact on earnings for the three and nine months ended September 30, 2017. DCP Midstream, a joint venture, processes certain of the Company’s pipeline customers’ natural gas to meet natural gas quality specifications in order for the natural gas to be transported on the Company’s Texas Eastern Transmission, LP system. DCP Midstream processes the natural gas and sells the NGLs that are extracted from the natural gas. A portion of the proceeds from those sales are retained by DCP Midstream and the balance is remitted to the Company. As a result, the Company received $15 million (US$12 million) and $34 million (US$26 million) classified as revenue from Transportation and other services in the Company’s Consolidated Statements of Earnings for the three and nine months ended September 30, 2017, respectively. The Company provides certain administrative and other services to certain operating entities acquired through the Merger Transaction, and recorded recoveries of costs from these affiliates of nil and $48 million (US$36 million) for the three and nine months ended September 30, 2017, respectively. Cost recoveries are classified as a reduction to Operating and administrative expense in the Consolidated Statements of Earnings. Outstanding receivables from these affiliates totalled $7 million (US$5 million).

15. CONTINGENCIES LAKEHEAD PIPELINE SYSTEM LINES 6A AND LINE 6B CRUDE OIL RELEASE Line 6B Crude Oil Release On July 26, 2010, a release of crude oil on Line 6B of EEP’s Lakehead Pipeline System was reported near Marshall, Michigan. As at September 30, 2017, EEP’s cumulative cost estimate for the Line 6B crude oil release remains at US$1.2 billion ($195 million after-tax attributable to Enbridge) including those costs that were considered probable and that could be reasonably estimated at September 30, 2017. As at September 30, 2017, EEP's remaining estimated liability is approximately US$64 million. Insurance Recoveries EEP is included in the comprehensive insurance program that is maintained by Enbridge for its subsidiaries and affiliates. As at September 30, 2017, EEP has recorded total insurance recoveries of US$547 million ($80 million after-tax attributable to Enbridge) for the Line 6B crude oil release out of the US$650 million applicable limit. Of the remaining US$103 million coverage limit, US$85 million was the subject matter of a lawsuit against one particular insurer. In March 2015, Enbridge reached an agreement with that insurer to submit the US$85 million claim to binding arbitration. On May 2, 2017, the arbitration panel issued a decision that was not favourable to Enbridge. As a result, EEP will not receive any additional insurance recoveries in connection with the Line 6B crude oil release. Legal and Regulatory Proceedings A number of United States governmental agencies and regulators initiated investigations into the Line 6B crude oil release. As at September 30, 2017, there are no claims pending against Enbridge, EEP or their affiliates in United States state courts in connection with the Line 6B crude oil release. Enbridge has accrued a provision for future legal costs and probable losses associated with the Line 6B crude oil release as described above in this footnote.


Line 6B Fines and Penalties As at September 30, 2017, EEP’s total estimated costs related to the Line 6B crude oil release include US$68 million in paid fines and penalties, which includes fines and penalties paid to the United States Department of Justice (DOJ) as discussed below. Consent Decree On May 23, 2017, the United States District Court for the Western District of Michigan, Southern Division, approved the Consent Decree. The Consent Decree is EEP’s signed settlement agreement with the United States Environmental Protection Agency and the DOJ regarding the Lines 6A and 6B crude oil releases. On June 15, 2017, Enbridge made a total payment of US$68 million as required by the Consent Decree, which reflects US$61 million for the civil penalty for the Line 6B release, US$1 million for the Line 6A release, and US$6 million for past removal costs and interest. TAX MATTERS Enbridge and its subsidiaries maintain tax liabilities related to uncertain tax positions. While fully supportable in the Company’s view, these tax positions, if challenged by tax authorities, may not be fully sustained on review. OTHER LITIGATION The Company and its subsidiaries are subject to various other legal and regulatory actions and proceedings which arise in the normal course of business, including interventions in regulatory proceedings and challenges to regulatory approvals and permits by special interest groups. While the final outcome of such actions and proceedings cannot be predicted with certainty, Management believes that the resolution of such actions and proceedings will not have a material impact on the Company’s interim consolidated financial position or results of operations.

16. SUBSEQUENT EVENTS On October 10, 2017, Enbridge completed an offering of US$700 million of floating rate senior unsecured notes. These notes carry an interest rate equal to the three-month LIBOR plus 40 basis points, and mature on January 10, 2020. On October 13, 2017, Enbridge completed an offering of $650 million of fixed-to-floating rate subordinated notes that mature in 60 years and are callable on or after year 10. For the initial 10 years, the notes carry a fixed interest rate of 5.4%. Subsequently, the interest rate will be set to equal the three-month Bankers' Acceptance Rate plus a margin of 325 basis points from year 10 to 30, and a margin of 400 basis points from year 30 to 60.


HIGHLIGHTS

Three months ended


September 30, 2017 2016 2017 2016

(unaudited, millions of Canadian dollars, except per share amounts) Earnings attributable to common shareholders

Liquids Pipelines 1,326 (87) 3,722 2,168 Gas Pipelines and Processing 615 67 1,636 147 Gas Distribution 83 20 511 342 Green Power and Transmission 20 34 121 124 Energy Services (150) (25) (12) (38) Eliminations and Other 101 (102) (255) 71 Earnings/(loss) before interest and income taxes 1,995 (93) 5,723 2,814 Interest expense (653) (397) (1,704) (1,178) Income tax recovery/(expense) (327) 253 (818) (174) (Earnings)/loss attributable to noncontrolling interests and

redeemable noncontrolling interests (168) 207 (633) 166

Preference share dividends (82) (73) (246) (217) Earnings/(loss) attributable to common shareholders 765 (103) 2,322 1,411 Earnings/(loss) per common share 0.47 (0.11) 1.57 1.56 Diluted earnings/(loss) per common share 0.47 (0.11) 1.56 1.55

Adjusted earnings Liquids Pipelines 976 941 2,884 2,947 Gas Pipelines and Processing 700 94 1,703 271 Gas Distribution 81 31 503 344 Green Power and Transmission 20 34 121 122 Energy Services (24) (15) (32) 33 Eliminations and Other (15) (84) (213) (253) Adjusted earnings before interest and income taxes1 1,738 1,001 4,966 3,464 Interest expense2 (614) (385) (1,667) (1,142) Income taxes2 (215) (77) (553) (384) Noncontrolling interests and redeemable noncontrolling interests2 (195) (29) (531) (165) Preference share dividends (82) (73) (246) (217) Adjusted earnings1 632 437 1,969 1,556 Adjusted earnings per common share1 0.39 0.47 1.33 1.72

Cash flow data Cash provided by operating activities 1,533 922 5,243 4,153 Cash used in investing activities (2,172) (1,268) (8,063) (5,200) Cash provided by financing activities 403 233 2,148 1,013

Available cash flow from operations3 Available cash flow from operations 1,334 852 3,873 2,834 Available cash flow from operations per common share 0.82 0.92 2.61 3.13

Dividends Common share dividends declared 1,001 496 2,552 1,448 Dividends paid per common share 0.610 0.530 1.803 1.590

Shares outstanding (millions) Weighted average common shares outstanding 1,635 922 1,482 905 Diluted weighted average common shares outstanding 1,642 922 1,490 913


Three months ended


September 30, 2017 2016 2017 2016

Operating data Liquids Pipelines - Average deliveries (thousands of bpd)

Canadian Mainline4 2,492 2,353 2,511 2,379 Lakehead System5 2,620 2,495 2,657 2,558 Regional Oil Sands System6 1,329 1,201 1,262 1,059

Gas Pipelines - Average throughput (mmcf/d) Alliance Pipeline Canada 1,530 1,544 1,559 1,571 Alliance Pipeline US 1,643 1,683 1,663 1,709 Canadian Midstream7 2,172 — 2,362 —

Gas Pipelines and Processing - Volumes processed (mmcf/d) Canadian Midstream8 1,626 — 1,794 — US Midstream9 6,294 1,046 6,204 1,118

Gas Pipelines and Processing - natural gas liquids (NGL) production (thousands of bpd)

US Midstream9 529 128 527 142 Gas Distribution - Enbridge Gas Distribution Inc. (EGD)

Volumes (billions of cubic feet) 43 43 286 295 Number of active customers (thousands)10 2,172 2,138 2,172 2,138 Heating degree days11

Actual 66 28 2,214 2,283 Forecast based on normal weather volume 62 65 2,413 2,374

Gas Distribution - Union Gas Limited (Union Gas) Volumes (billions of cubic feet) 203 — 574 — Number of active customers (thousands)10 1,470 — 1,470 — Heating degree days11

Actual 162 — 1,255 — Forecast based on normal weather volume 170 — 1,260 —

1 Adjusted EBIT, adjusted earnings and adjusted earnings per common share are non-GAAP measures that do not have any standardized meaning prescribed by GAAP - see Non-GAAP Measures.

2 These balances are presented net of adjusting items. 3 ACFFO is defined as cash flow provided by operating activities before changes in operating assets and liabilities (including

changes in environmental liabilities) less distributions to noncontrolling interests and redeemable noncontrolling interests, preference share dividends and maintenance capital expenditures, and further adjusted for unusual, non-recurring or non-operating factors. ACFFO and ACFFO per common share are non-GAAP measures that do not have any standardized meaning prescribed by GAAP.

4 Canadian Mainline throughput volume represents mainline system deliveries ex-Gretna, Manitoba which is made up of United States and eastern Canada deliveries originating from western Canada.

5 Lakehead Pipeline System (Lakehead System) throughput volume represents mainline system deliveries to the United States mid-west and eastern Canada.

6 Volumes are for the Athabasca mainline, Athabasca Twin, Waupisoo Pipeline and Woodland Pipeline and exclude laterals on the Regional Oil Sands System.

7 Canadian Midstream throughput volumes represent throughput from the Western Canada Transmission & Processing assets only.

8 Canadian Midstream processing volumes represent the volumes processed through the Tupper Main and Tupper West gas plants and the Western Canada Transmission & Processing assets.

9 US Midstream processing volumes and NGL production represent the volumes processed and produced from the Field Services assets and the Midcoast Energy Partnership assets as well as the Aux Sable processing plant.

10 Number of active customers is the number of natural gas consuming EGD and Union Gas customers at the end of the period. 11 Heating degree days is a measure of coldness that is indicative of volumetric requirements for natural gas utilized for heating

purposes in EGD’s and Union Gas’s franchise area. It is calculated by accumulating, for the fiscal period, the total number of degrees each day by which the daily mean temperature falls below 18 degrees Celsius. The figures given are those accumulated in the Greater Toronto Area.


SHAREHOLDER INFORMATION either case free of brokerage or other charges. Registrar and Transfer Agent in Canada Share purchase cut-off for the 2017 fourth Inquiries regarding the Dividend Reinvestment and quarter optional cash payment to purchase Share Purchase Plan, change of address, share additional shares is November 24, 2017. transfer, lost certificates, dividends, and duplicate mailings should be directed to: Investor Relations Shareholder inquiries regarding the Company’s CST Trust Company financial and operating performance should be P.O. Box 700 directed to: Station B Montreal, Quebec H3B 3K3 Investor Relations Toll free: (800) 387-0825 Enbridge Inc. 200, 425 – 1st Street S.W. Dividend Reinvestment & Share Purchase Plan Calgary, Alberta, Canada T2P 3L8 Enbridge Inc. offers a Dividend Reinvestment and Toll free: (800) 481-2804 Share Purchase Plan that enables shareholders to Internet: www.enbridge.com reinvest their cash dividends in common shares, or to make payments to purchase additional shares, in November 2, 2017

200, 425 - 1st Street S.W.Calgary, Alberta, Canada T2P 3L8

Telephone: 403-231-3900Fax: 403-231-3920Toll-free: 800-481-2804

enbridge.com

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Enbridge Inc./media... · ENBRIDGE INC. THIRD QUARTER REPORT 2017 | 1 Q3 HIGHLIGHTS (all financial...

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